world bank document ix: distribution expansion and rehabilitation project september 17, 1986 energy...

Document of

The World Bank

FOR OFFICIAL USE ONLY

Report No. 6032-CE

STAFF APPRAISAL REPORT

SRI LANKA

POWER IX: DISTRIBUTION EXPANSION AND REHABILITATION PROJECT

September 17, 1986

Energy DivisionSouth Asia Projects Department

This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank atorimtion,.

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SRI LANLCA


CURRENCY EQUIVALENTS

US$1.0 - = SR Rs 27.4-SL Rs 1.0 = US$0.036

MEASURES AND EQUIVALENT

i kilometer (kin) = 0.6214 mile1 kilovolt (kV) = 1,000 volt-s1 megavolt ampere (MVA) 1 million volt amperes

1,0f00 kilovolt amperes

I kilowatt (kW) 1,000 watts1 megawatt (MW) = 1 million watts

= 1,000 kilowatts1 kilowatt hour (kWh) = 1,000 watt hours1 gigawatt hour (GWh) = 1 million kilowatt hours

kgoe = kilogram oil equivalent

toe = ton oil equivalent

ABBREVIATIONS AND ACRONYMS

ADB = Asian Development BankAMP = Accelerated Mahaweli ProgramCEB = Ceylon Electricity BoardCPC = Ceylon Petroleum CorporationDDRB = Distribution Development and Rehabilitation Branch

DGEU = Department of Government Electrical UndertakingsEIRR - Economic Internal Rate of ReturnESMAP = Energy Sector Management Assistance ProgramFY = Fiscal YearCOSL = Government of Sri LankaGTZ 5 German Agency for Technical Cooperation1GB = International Competitive BiddingKfW = Kreditanstalt fuer WiederaufbauLECO = Lanka Electric Company LimitedLRC = Loss Reduction CellLRMC = Long Run Marginal CostLV = Low VoltageMPE = Ministry of Power and EnergyMASL = Mahaweli Authority of Sri LankaMV = Medium VoltageODA = Overseas Development Administration (UK)TOR = Terms of ReferenceUSAID = United States Agency for International

Development

CEB's Fiscal Year is the calendar year.

FOR OMCIAL USE ONLY

SRI LANKA

POWER IX: DISTRIBUTION EXPANSION AND REHAILITATION PROJECT

Credit and Project Summary

Borrower s Democratic Socialist Republic of Sri Lanka.

Beneficiary : Ceylon Electricity Board (CEB).

Amount- : SDR 43.2 million (US$52.0 million equivalent).

Terms : Standard.

Onlending Terms 3 The Government would relend the credit proceeds toCEB at an interest rate of ten percent per annum,repayable over 20 years, including five-year graceperiod. The Covernment would bear the foreignexchange risk.

Project Description : The principal objectives of the Project are to improvethe reliability and quality of power supply, to reducelosses to economic levels, and expand the distributionsystem to meet the forecast demand for electricity.The Project consists of a four-year time slice ofCEB's distribution rehabilitation and expansionprogram. The project would comprise the erection ofabout 950 km of 33-kV lines, extension and rehabili-tation of low voltage distribution networks in Colombocity and elsewhere in Sri Lanka, and technical assist-ance to CEB.

Risks: The Project is straightforward and no unusual risksare foreseen. Delay in implementation is, however,possible since the project is spread over a largegeographical area and has many interfaces with theexisting network. This risk would be minimizedthrough the provision of project management assistanceby cossultants. The packaging of the Project, whichuses supply and erect contracts and clearly identifiescontractual responsibility, would also minimize thisrisk. Slippage could occur due to delays in appoint-ing contractors and problems in acquiring right ofway. Any delays in the appointmerlt of contractorswould be minimized by engaging consultants prior tocredit effectiveness. Most of the distribution lineswould be constructed adjacent to public roadways andSri Lanka's existing laws give adequate powers to CEBto acquire right of way. Thus the acquisition ofright of way is not expected to delay project imple-mentation.

This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

Local Foreign Total-----------US$ million

Estimated Cost

Main 33-kY Lines 11.7 18.3 30.0Other hV Networks 5.0 9.5 14.5Rationalization of LV Networks 3.7 3.8 7.5Colombo City Network 7.9 9.9 17.8Network Rehabilitation 2.7 4.8 7.5Consultancy, Project Management

& Training 1.4 4.3 5.7Total Baseline Costs 32.4 50.6 83.0

Physical Contingencies 3.2 5.1 8.3Price Contingencies 7.5 9.3 16.8

Total Project Costs 1/ 43.1 65.0 W08.1

Financing Plan

IDA 52.0 52.0ODA - 13.0 13.0CEB 43.1 - 43.1

43.1 65.0 108.1

Estimated Disbursements

IDA FY87 FY88 FY89 FY90 FY91 FY92… … US$------ 5SS million-----------------

Annual 1 12 15 13 7 4Cumulative 1 13 28 41 48 52

Rate of Return: 11l

Maps: IBRD 19433RIBRD 19434R

1/ Including taxes and duties of US$16.0 million.

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SRI LANKA



Table of Contents

Page No.

I. ENERGY SECTOR *...........*e*.*@... ................. 1

A. Energy Resources .... I............ ............ . 1B. Organization of Energy Sector ...................... 2C. Energy Consumption 2.................... 2D. Energy Pricing 2..................................... 2E. The Bank Group's Involvement in the Energy Sector .. 3F. GOSL's Strategy in the Energy Sector * .............. 3G. The Bank Group's Strategy in the Power Subsector ... 4

II. THE BORROWER ........ ***..***.****.******........*.... 4

III. THE PROJECT ................... ......................... 11

IV. FINANCES ......... ....... *........ .......... 17

V. JUSTIFICATION ....................... 28

A. Electricity Demand Forecast ..... ................... 28B. Least Cost Alternative ...... ....................... 29C. Economic Internal Rate of Return ................... 29D. Justification for Bank Group Involvement ........... 30

VI. AGREEMENTS AND RECOMMENDATION .......................... 30

This report is based on the findings of an appraisal mission to Sri Lankain October 1985. Mission members included Messrs. M.G. Webb (Economist),S. Babbar (Power Engineer), R. Sharma (Financial Analyst), W. Kupper(Consultant Power Engineer), and A. Gulstone (Power Engineer).

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Page No(s).

ANNEXES

1.1 Energy Sector Organization-Chart ....................... 332.1 CEB's Organization Chart ............................ ... 342.2 Details of Generation and Plant Capacities 1975-1985 ... 352.3 Energy and Capacity Balances 1975-1985 ................. 362.4 Number of Consumers and Revenue 1975-1985 ....... ...... 372.5 CEB's Least Cost Generation Expansion Plan ............. 38-2.6 Forecast Capacity and Energy Balances 1985-1995 ........ 393.1 Project Description ................ ....... 40-463.2 Detailed -Cost Tab7es ................ ..... 47-493.3 Project Implementation Schedule ........................ 503.4 Disbursement Profile ........ ......... .................. 513.5 Analysis of System Losses .............................. 52-543.6 Equipment Technical Parameters ......................... 55-574.1 Actual and Forecast Income Statements for CE8 ..B...... 584.2 Actual and Forecast Sources and

Application of Funds Statements for CEB ............. 594.3 Actual and Forecast Balance Sheets for CE8 ............. 604.4 Assumptions for Financial Projections .................. 614.5 CEB's 1985 Tariffs *.................................... 624.6 CEB's Investment Program 1986-1995 ..................... 634.7 Fixed Asset Formation ... .............................. 645.1 Economic Internal Rate of Return ........ , .............. 65-696.1 Data and Documents available in Project File ........... 70

MAPS

IRBD Nos. 19433R and 19434R.

SRI LANKA



I. ENERCY SECTOR

A. Energy Resources

1.01 Sri Lanka has few indigenous energy resources. There are no knownhydrocarbon reserves, but a modest petroleum exploration program is uiderway.The major indigenous energy resources are hydropower and fuelwocd. Thehydropower potential is estimated to be about 2,000 HW, with an energy poten-tial, under average hydrological conditions, of about 5,800 GWh a year. Themajor hydropower resources are concentrated in the southern half of thecountry in basically five river systems: Mahaweli Ganga, Kelani Canga, KaluGar.ga, Nihwala Ganga and Walawa Ganga. The centerpiece of hydropowerdevelopment has been the Accelerated Mahaweli Program (AMP), which will add533 MW (Victoria 210 NW, Kotmale 201 MW, and Randenigala 122 MW) to CeylonElectricity Board's (CEB) installed capacity by 1988. The lack of detailedknowledge of the remaining hydropower potential and the technically feasibledevelopments is one of the major constraints affecting hydropower developmentin the country. This issue will be addressed in a study of hydropower poten-tial under financing by the Government of the Federal Republic of Germanythrough the Gesellschaft fur Technische Zusammenarbeit (GTZ). Consultants(Lahmeyer/Decon) were appointed in January 1986 and the study commenced onApril 1, 1986.

1.02 At present-fuelwood is estimated to supply about 55% of Sri Lanka'sgross energy supply. However, incremental wood production from the naturalregeneration of forests, agricultural residues and rubber replanting, etc.,is estimated to be tess than half of the annual consumption of fuelwood(about five million tons). The balance of wood supply has come mainly fromdeforestation, and the island's natural forest cover has declined from about7 million acres in 1960 to about 4 million acres in 1980. Deforestation willincrease the demand for commercial energy, with the substitution of petroleumproducts for fuelwood. This could result in a substantial increase in thefuel import bill. The Government of Sri Lanka (GOSL) is aware of theseissues and agrees with the Association that a key element in their resolutionwould be a large and comprehensive reforestation program. A forestry MasterPlan is being prepared as part of the Bank-assisted Forestry I Project(Credit 1317-CE). Reforestation programs, under which GOSL is planning totreble both the acreage and density of tree planting, are being developedwithin the context of ongoing United States Agency for International Develop-ment (USAID) and Asian Development Bank (ADS) assisted fuetwood projects.When completed, the USAID project aims at providing between 10% and 15% ofthe country's fuelwood requirements. Efforts to improve the supply of fuel-wood are being complemented by action on the demand side to encourage the useof more fuel-efficient woodstoves. A new woodstove has been developed underthe auspices of the energy conservation task force (para 1.03), and GOSL ispromoting its use through a demonstration program and by providing incentivesto consumers to acquire the new woodstove.

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B. Organization of the Energy Sector

1.03 Until late 1982, a major institutionat constraint was the relativelylarge number of ministries and line agencies involved in the different energysubsectors, and the lack of effective coordination between them. GOSLinitiated a major institutional reform in October 1982, when it created anEnergy Coordinating Team (ECT) in the Ministry of Power and Energy. The mainpurpose-of ECT is coordination of the work of the relevant ministries andline agencies and tne prevention of duplication. ECT consists primarily ofthree coordinating task forces, covering^energy planning, energy conservationand renewable energy, and, their support staff. In September- 1985, theSecretary, Ministry of Power and Energy, was appointed to manage ECT. Energypolicy coordination was also strengthened in 1984 when the Ceylon PetroleumCorporation was transferred from the Ministry of Industries to the Ministryof Power and Energy, thus reducing the number of ministries involved in theenergy sector, and in 1983 when Lanka Electric Company (LECO) was created, togradually take over local authority distribution systems (paras 2.04 and2.05). The organizational structure of the energy sector is shown inAnnex 1.1.

C. Energy Consumption

1.04 Per capita consumption of commercial energy in Sri Lanka is about145 kgoe per annum, just over 50% of the average for the low-incomecountries. Total per capita consumption of energy is about 240 kgoe perannum, about 65% of which is supplied by non-commercial energy, principallyfuelwood, about 30% by petroleum products and 5% by hydropower. Energyconsumption has been growing relatively slowly. Between 1973 and 1983 totalenergy consumption increased at the average annual rate of about 2.5%, com-pared with 3.4% for commercial energy, and an annual growth rate of 5.2% forreal GDP. Thus the GDP energy elasticity was relatively low at only about0.5 during the period 1973-1983. GOSL has projected an annual growth ratefor real GDP of 5% for the period 1986-1990. If the energy elasticityremains at 0.5, then the total consumption of energy would inc-ease fromabout 3.6 million toe in 1983 to about 4.3 million toe in 1990.

D. Energy Pricing

1.05 Until 1978, for social and political reasons, energy prices did notreflect the economic costs of supply. Since then, however, petroleum productprices have been generally set at or above border price levels. In July 1983the price of kerosene was increased by about 27% to this level following theelimination of the general subsidy on kerosene. The purchasing power oflow-income households was protected by the simultaneous increase in the valueof kerosene stamps, which are provided to about half of the population. Inearly 1986 petroleum product prices were substantially above border pricelevels. GOSL did not reduce retail prices following the fall in interna-tional prices but used the opportunity to mobilize resources to reduce thebudget deficit. CEB's electricity tariffs have been raised several times inrecent years, most recently in March 1985. During the period 1978-1985,average revenue per kWh, including the fuel adjustment charge (para 4.08),increased at the average annual rate of about 46%, representing an averageannual increase in real terms of 26%. The increases in tariff rates were

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accompanied by significent changes in the tariff structure. Thus, the 1978tariff revision included provision for a £zel adjustment charge, and the 1980tariff replaced the declining block tariff for domestic consumers by anincreasing block tariff, including -a lifeline rate to enable low incomeconsumers to afford the electricity required to meet their basic needs. In1980, CEB agreed under the Sixth Power Project (Credit 1048-CE) to carry outa tariff study based on long-run marginal cost (LRMC), to implement anyagreed recommendations, and to update the study periodically. A study wasundertaken in 1981 and a revised tariff was introduced in June 1982. Thestudy was updated in 1984 and revised tariffs were introduced in March 1985(Annex 4.5). The 1985 tariff structure includes separate energy and demandcharges for hotel, industrial and general purpose consumers with contractdemands exceeding- 40 kVA, -and optional time of day energy rates forindustrial and hotel consumers. The average revenue per kWh, which is set tomeet CEB's financial objectives (para 4.01), is estimated to be about 80X ofLRMC.

E. The Bank Group's Involvement in the Energy Sector

1.06 To date the Bank Group has supported the development of the energysector through eight operations in the power subsector, involving five loansand three credits. The amount of the Bar: Group funds committed throughthese operations totals US$166.7 million, representing about 17? of totalBank Group resources committed to Sri Lanka up to December 31, 1985. TheBank Group's involvement with Sri Lanka's power subsector began in 1954 whena loan of US$19.1 million (Loan 101-CE) was made to GOSL to help finance a25 KW expansion of the Aberdeen-Laksapana hydroelectric scheme. Since then,the Bank Group has continued to be actively involved in providing the resour-ces needed for the development of the subsector, in terms of both itscapacity to meet demand at least cost and institutional reforms. Of theeight projects, six have been completed satisfactorily and two (Sixth PowerProject, Credit 1048-CE, and Seventh Power Project, Credit 1210-CE) are stillunderway. These two projects have proceeded slowly because of a number ofdifficulties, including civil unrest and the limited capability of CEB'smanagement to cope with the ever growing workload associated with theincreasing size and complexity of the power system. This problem wasapparent before the Sixth Power Project was approved in 1980. Consequently,the Association financed consultants' studies of CEB's management andorganization under the Sixth Power Project (Credi- 1048-CE). The consultantsrecommended a new organizational structure to make CEB more responsive to therequirements of a greatLy expanded system. Their recommendations wereaccepted and CEB is implementing the suggested reorganization, which involvesits decentralization (para 2.02). Although much still remains to be done,particularly in staffing (para 2.07), the Bank Group agrees that the neworganization provides an adequate operational framework and addresses somekey management deficiencies.

F. GOSL's Strategy in the Energy Sector

1.07 GOSL's energy strategy includes measures that address both the demandand supply of energy. On the demand side, GOSL has been promoting energyconservation and the reduction of waste, and has been encouraging the effi-cient use and allocation of energy resources by relating energy prices totheir economic costs of supply. On the supply side, particular emphasis has

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been placed on substituting imported petroleu- products with indigen0usresources, principally hydropower. Other majoz objectives being pursued bythe government in the energy sector include: (a) improving the quality andreliability of electricity supply and efficiency in the operation of thepower system; and (b) improving efficiency of use and increasing theavailability of renewable resources to meet the growing demand for energy inrural areas. In line with the priority given to energy development, about13% of the public investment program for 1985-89 is allocated to projects inthe power subsector.

G. The Bank Group's Strategy in the Power Subsector-

1.08 The objectives of the Bank Group's assistance in the power subsectorhave been determined in the course of a continuing dialogue with GOSL on icSstrategy for the development of the energy sector. Assistance both has beenand is aimed at supporting efforts to: (a) meet the forecast demand forelectricity at least cost through the development of an appropriate mix ofgenerating plants and the development of efficient transmission and distribu-tion systems; (b) assist in institution building and strengthen the financialmanagement of CEB through the provision of consulting services (para 4.02)and training for CEB staff; (c) rationalize the consumption of energy throughthe reform of tariff structures and setting tariff rates based on the coststo Sri Lanka of meeting consumers' demands for electricity (para 1.05); and(d) increase resource mobilization in the power subsector by settingappropriate financial objectives for CEB and controlling accounts receivable(paras 4.10 and 4.11). Although progress has been made in all of theseareas, further improvements are necessary. In particular, additional effortsare needed to: (i) reduce losses in transmission and distribution;(ii) reinforce and extend transmission systems to supply new consumers andimprove the quality of supply; and (iii) further strengthen the managementand staffing of CEB by improving the conditions of service and through train-ing. These issues are addressed by the Project.

II. THE BORROWER

Organization of CEB

2.01 CEB, the beneficiary, is a statutory corporation established by theCEO Act, No. 17 of 1969 (1969 CEB Act). It is responsible for the generationand transmission of electricity throughout Sri Lanka, and for distributionexcept in those areas where distribution systems are operated by licensees(local authorities) and, since 1984, Lanka Electric Company (Private)Limited (LECO). CEB's management consists of a seven-member Board, themembers of which are appointed by the Minister of Power and Energy and may beremoved at any time, serve a three to five-year term and may be reappointed.The Chairman is appointed from among the Board members. While the Chairmanis responsible through the Board for policy matters and close liaison withthe government, the General Manager (GM) is CEB's Chief ExecutiveOfficer (CEO). He is responsible for the overall direction and control ofCEB's day-to-day business. The GM is appointed, on the basis of seniorityand merit, from-CEB's staff. In recent years there has been a rapid turnoverof persons holding this position (there were three GMs in the period

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1982-84), and this led to discontinuity and an increase in the Chairman'sinvolvement in CE8's day-to-day business. However, the situation improvedwith the appointment of the present GM in 1984, who is playing an active roleas the CEO.

2.02 CEB's original organizational structure was designed by Urwick Inter-national Ltd. (United Kingdom), management consultants, in the early 1970sunder Loan 636-CE. In 1981, CER again retained the services of these con-sultants under the Sixth Power Project (Credit 1048-CE) to: re-examine itsorganizational structure, since the existing structure was considered to beinappropriate for the enlarged size and responsibilities of CEB; redesignCEB's accounting organization and systems; and implement a modern system forinventory control and management (para 4.02). Urwick recommended adecentralized organization consisting of (i) seven departments at CEB'sHeadquarters; (ii) two operating regions with several divisions under them;and (iii) a Generation Group responsible for three complexes and a systemcontrol center. In September 1982, CEB's Board agreed to restructure CEB inaccordance with the consultants' recommendations, and implementation began inJanuary 1984 (CEB's organization chart is shown in Annex 2.1). Under the neworganization the regions are responsible for the extension and reinforcementof distribution systems. Construction units are being established in theregions to allow them to undertake this work. However, CEB is to ceaseundertaking major construction work using its own directly employed labor.Contracts for large projects will be let to outside contractors under thesupervision of CEB's Headquarters.

2.03 Implementation of the new organization has proceeded at a slower pacethan expected, and consequently many of the new management systems areoperating only partially. In an effort to expedite implementation, CEBrequested the consultants to prepare detailed procedures for the neworganization, provide systems training to selected staff, and prepare manualsfor systems operations for all CEB's activities. The consultants produceddrafts for twenty-six operating and four functional manuals for CEB approvaland eventual distribution. The finalization of these manuals has proceededslowly and some of the manuals are still in the draft stage. Thus some ofthe major benefits anticipated from the reorganization exercise have notmaterialized, and CEB is still operating many systems under the old proce-dures. In recognition of this problem, CEB extended its contract with UrwickInternational Ltd. (pare 2.02) to assist in monitoring the implementation ofthe new procedures. Subsequently, CEB agreed to hire local consultants to,in effect, monitor the stage of implementation of the new procedures.Monitoring is now underway under the supervision of Urwick International Ltd.in association with M/S Macan Markar, a local firm of accountants. Fullimplementation of the new organizational structure and the finalization ofthe associated operating manuals is considered to be an important step instrengthening CEB, and is required to enable it to manage operations andinvestments efficiently, including the Project. Therefore, in order toensure that CEB's organizational structure does not hinder its development asa modern utility, the completion by CEB of the restructuring of itsorgnization as approved by its Board of Directors in September 1982 andcompletion and distribution of all related operational and functionalmanuals, would be conditions of effectiveness of the Credit (para 6.05(a)).

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2.04 The new organization is concerned with improving the efficiency ofCEB given its present functions. The perennial problems of local authoritieswith regard to their electricity distribution functions require longer termpolicy decisions by GOSL to rationalize the electricity distributionindustry. Under the existing organization of the power subsector, CEB isdirectly responsible for about 80% of total sales at the distribution level,with licensees (local authorities) being responsible for the other 20%. Untilearly 1985 there were 218 licensees, but that number is -gradually beingreduced as Lanka Electric Company (LECO), which GOSL formed in September 1983in an effort to address the deterioration in the quality of service at thedistribution level, takes over the distribution systems operated by licen-sees. LEGO was established under the Companies Act. Its shates are held byCEO, the Urban Development Authority (UDA), and local authorities (non-votingshares only). One reason for the establishment of LECO under the CompaniesAct was to ensure that it would not be subject to government regulations onconditions of service for its employees. LECO, has so far taken over fivelicensees and has identified another 15 to be taken over in the near future.GOSL's policy for the reorganization of electricity distribution is supportedby both the Bank Group and the ADB. The latter is supporting LECO throughits Secondary Towns Distribution Project.

2.05 A major defect with the current arrangements to reorganize the stub-sector is that LECO, in taking over licensees, does not achieve a viableconsumer mix; in particular it has a preponderance of domestic consumers andinsufficient high-voltage consumers. In addition, the long-term takeover ofall licensees by LECO would lead to a fragmented area of operations due tothe geographic separation of many licensees. The solution to this problemmay involve LECO taking over both licensees and consumers served by CEB inareas contiguous to those now served, or to be served in the future, by LECO.In recognition of the issues posed by licensees, LECO commissioned thedevelopment of a Master Plan (the draft of which was completed in mid-1986 byconsultants funded by ADB) which will suggest a framework for its futuredevelopment and determine the investment required to rehabilitate the dis-tribution systems of licensees. This Master Plan should be complemented by asimilar plan for the distribution systems operated by CEB, and the two plansintegrated to provide an overall plan to rationalize electricity distributionin Sri Lanka. The resources required to rehabilitate licensees' distributionsystems, in order to facilitate their takeover by either CEB or LECO, couldbe the subject of future Bank Group operations (para 2.14). During nego-tiations, CEB agreed to prepare and submit to the Association for review byJuly 31, 1988, a master plan for the development of distribution systems inSri Lanka; and GOSL agreed to initiate by October 31, 1988, alpro1rn satin-factory to the Association to rationalize the institutional arrangemento forthe distribution of electricity in Sri Lanka (paras 6.01 and 6.03(a)).

CEB Management and Staffing

2.06 In January 1986, CEB had about 12,500 employees and served about390,000 consumers, representing a consumer/employee ratio of about 3211.Although it is Low, this ratio represents a considerable improvement over the1975 ratio of 13:1. CEB has been suffering from a number of manpowerproblems, which mean that it is simultaneously oversteEfed in some depart-ments and deficient in key personnel in many important functional grebe*CEB's manpower policy is to limit the recruitment of new otaff and to improve

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staff productivity through appropriate training at its proposed new trainingschool (para 2.08). In order to develop a medium term strategy to addressits manpower problems, during negotiations, CRB agreed to prepare and submitto the Association by March 31, 1987, planned staffing levels and numbers forthe period 1987-1989 (para 6.03(b)).

2.07 In recent years CEB has -had considerable- difficulty in retainingexperienced engineers and accountants, and this has caused a shortage of keypersonnel. At the end of 1985 it had only about 300 qualified engineers; ofwhom less than 101 had-more than five years experience with CEB. Manyengineers had left to take higher paid posts in the private sector or over-seas. The exodus of staff has been increased by a promotion system whichemphasizes seniority rather than merit. In 1984, CER engaged managementconsultants Urwick International Ltd. (United. Kingdom) to study its staffingjroblem. Urwick's main proposal concerned the removal of the govern-ment-imposed ceiling on remuneration and the introduction of a new salaryetructure with increases of 200% at the highest levels. Government regula-tions on conditions of service generally limit total monthly remuneration toRG 5,200 plus a cost of living allowance of Rs 500. These regulations applythroughout the public sector and thus the remuneration issue is a publicnector issue. However, CEB does have some room for maneuver through thepayment of risk and productivity allowances and bonuses up to the equivalento-f one month's salary a year. Keeping in view both CEB's long-term manpowerrequirements and the government-imposed ceiling on remuneration, CEB, duringnegotiations, agreed to submit to the Association by June 30, 1987, and putii,ia effect not later than December 31, 1987, a scheme of incentives and aprormfition,policy based on merit and other appropriate factors (para 6.03(c)).

fraiirdr,

?.fto CEO is fully cognizant of the role to be played by training in meet-itig, itri tiaffing requirements, and in 1984 it established a training sectioni-u (tirg of the Chief Engineer for Education and Training. The existingtrtnire, £nfacilities are inadequate to meet the needs of a rapidly growingkitility, The*se facilities include a small residential training center atfCoitlIrvoagh (about 122 k1m from Colombo) which has a capacity for 40 studentsotod provides baoic training in electrical and mechanical skills through6iX-(iloII roornes. The Castlereagh center suffers from two major problems:tanly, itSi omall capacity which is inadequate to meet CEB's existing andff*stt'1ett irttiing requirements; and secondly, its remote location which makest dif1iitilt to retain good instructors. Consequently, in 1983 CEB proposed

ttfXs I tl IWW I,tkitling center should be constructed near Colombo.

dt4i1' ln 1984/$5, Ileetricite de France prepared a feasibility study for atu 'P' e(ititc) Trainiing Center to be located close to Colombo and capable ofrgliilr, kill to 11000 trainees a year. This study was reviewed by the Associa-

tf4 li til i t1uit1 fo lie accept.able after the capacity of the center was reducedth akttt 'lti( trainiing placen with a capability of handling about 400 trainees

V'il!a.a ,hit1ii cAipjililhy iS consistent with CEB's forecast total technical"'t"n4'jf jttiirfjMey t of abiout 10,100 in 1995. CEB plans to finance theti it;l t t iz llu lw rupjwued center from its own resources. However, COSL has

4pt1u1'1del tIhAt thk cotsl s,P equipmenit for the center, estimated to be about4t6pl**}t11J ibolnld Fs finoneed from savings under the ongoing Power VI andViuj V Vi " 2his request is being considered by the Association.

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2.10 CEB has a shortage of staff trained in modern methods for the con-struction and maintenance of its distribution systems. This is partly due toits inadequate training facilities. The Project contains a training elementto address this issue (paras 3.03 and 3.08).

Existing Facilities

2.11 tn December 1985 CEB's total installed generating capacity was949 MW, comprising 679 MW hydroelectric plant (including 210 MW at Victoriaand 134 MW at Kotmale, the first stations commissioned under the AcceleratedMahaweli Program), and 270 MW thermal plant (including 120 MM gas turbinesand 80 MW of diesel capacity--Annex 2.2). Total installed capacity increasedat the average annual rate of about 101 in the period 1975-85 (it was 361 KWin 1975). During this period the hydro thermal plant mix changed from 81:19to 72:28. The major generating stations and load centers are interconnectedby a 132-kV transmission grid (805 km), consisting of double andsingle-circuit lines. There are also 286 km of 66-kV transmission lineswhich are to be replaced largely by 132-kV connections. Under the Seventh(Mahaweli Transmission) Power Project (Credit 1210-CE), 220-kV lines arebeing constructed with planned completion by mid-1986 to meet larger trans-mission capacities required to transmit the increasing Mahaweli hydropowercapacity to the Colombo area. The transmission network is, generally, ingood condition.

2.12 The subtransmission system comprises about 7,800 km of 33-kY lines,about 2,500 km of 11-kV lines and about 5,000 consumer substations. Thephysical condition of the distribution networks is generally unsatisfactory,partly because many of the networks are overloaded as a result of the largeincrease in the number of consumers in recent years and partly as a result ofpoor maintenance (para 2.13). CEB's management consultants, Urwick Interna-tional Ltd. (United Kingdom), recommended, and CEB accepted, that each Areashould prepare and maintain plant and equipment registers, and preparequarterly maintenance plans. However, in a number of Areas the implementa-tion of such maintenance plans has been hindered by shortages of skilledlinesmen and other staff. The Project would upgrade the physical conditionof the distribution networks and provide training for linesmen.

Maintenance of Facilities

2.13 The high level of losses and poor performance of some of generatingfacilities is attributable in part to inadequate maintenance because of ashortage of technical personnel. The shortage of personnel for the main-tenance of distribution systems will be addressed through the Project bytraining CEB staff in modern techniques for the construction and maintenanceof distribution systems (para 3.08). Tools and equipment to upgrade thepresent distribution facilities would also be procured under the Project(para 3.03). This needs to be complemented by the implementation of a datedprogram for the planned maintenance of its thermal and hydropower generatingfacilities and upgrading plant maintenance systems. During negotiations, CEBagreed to submit to the Association by November 30, 1986, the maintenanceprogram for its generating facilities for 1987(para 6.03(d)}. The implemen-tation of this program will be monitored during supervisions. CEB alsoagreed to employ consultants with adequate experience in the operation of

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similar plant to review by December 31, 1987, the plant maintenance system atthe Sapugaskanda diesel power station and thereafter implement the improve-ments recommended by the consultants according to a schedule acceptable tothe Association (para 6.03(e)). CEB would thereafter review the maintenancesystems at the other thermal generating stations based on the experiencegained at the diesel power station.

System Losses

2.14 Losses, as a percentage of gross generation, on CEB's supply systemincreased from 10.5% in 1975 to a peak of 19.6% in 1981 and then declined toabout 17.1% in 1985 (Annex 2.3). Most of the losses (about seven percentagepoints) occur in the 33-kV subtransmission system. Non-technical losses arelow in CEB's system, being only about one percentage point. The problem oflosses has been studied by the UNDP/World Bank Energy -Sector ManagementAssistance Program (ESMAP), I/ and in 1983 CEB established a Loss ReductionCell (LRC) to address the problem. 2/ According to both that report andanalysis undertaken by LRC, the principal cause of the high losses is under-investment in medium and low voltage distribution lines, resulting in over-loading and poor voltage conditions, and low power factors. The ESNAP reportidentified a number of measures to reduce technical lossea. These have beenincluded in the Project. Losses are also high in the distribution systemsoper4ted by local authorities (licensees). In 1985 these losses wereestimated to be about 25Z of CEB's bulk supply to licensees. The problem oflosses in licensees' distribution systems is being addressed by the ADBthrough its FY84 Secondary Towns Distribution Project and a planned operationin FY87. However, due to the large number of licensees (over 200) the reduc-tion of losses in their distribution systems in a timely manner may requireBank Group support through a future operation.

2.15 Although dated loss reduction programs have not been formulated, itis anticipated that the implementation of the measures included in theProject would reduce system losses from about 18% of gross generation in 1986to about 12% in 1994.

Planned Generation

2.16 Generation planning for CEB's interconnected system is carried out byits Generation and Transmission Planning Department using the computer basedWASP-III optimization model. CBS has an annual generation expansion planningcycle; this begins with the preparation of the load forecast by the Commer-cial branch in July and is followed in August/September by the preparation ofthe least cost generation expansion plan using WASP-III. This plan isintegrated with the transmission and distribution expansion plans, and the

1/ Sri Lanka: Power System Loss Reduction Study, July 1983; Joint UNDP/WorldBank Energy Sector Management Assistance Program, Activity CompletionReport No. 007/83.

2/ In 1985, LRC was renamed tne Distribution Development and RehabilitationBranch (DDRB).

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resultant aggregated plan is used by the Finance Department for the prepara-tion of CEB's annual financiat plan. Details of the latest (September 1985)least cost generation expansion plan and forecast energy and capacity balan-ces are given in Annexes 2.5 and 2.6, and the phasing of expenditure inAnnex 4.6. The expansion plan has been reviewed by IDA and found to besatisfactory. At negotiations, CEB and GOSL agreed to annually update andreview with the Association the long-term development plan of the Board(para 4.16).

2.17 CEB's total installed capacity is projected to increase from about950 MW in 1985 to about 1250 MW in 1990 and about 1700 MW in 1995. Effectivecapacity is projected to increase from about 728 MW in 1985 to about 1151 MW.in 1990 and about 1476 MW in 1995. Hydropower projects under construction orfirmly planned comprise: extensions at Canyon (1x30 MW) and Kotmale(1x67 MW) to be commissioned in 1987 and 1988 respectively, the commissioningof the Randenigala project (122 MW) in 1987, to be followed by Rantambe(49 MW) in 1990, Samanalawewa (120 MW) in 1991 and Broadlands (20 MW) in 1992(Annex 2.5). Thermal projects comprise: rehabilitation of the Kelanitissaoil-fired plant (50 MW) in 1989, and construction of the Trincomaleecoal-fired station, with the first unit (150 MW) being commissioned in 1993.With the exception of the Trincomalee and Broadlands projects, financing hasbeen secured or is being negotiated for all of these projects and they shouldbe commissioned as planned. Annex 2.6 shows that the completion of thisprogram as planned would enable CEB to meet its load forecast at its plannedquality of service.

Transmission

2.18 Transmission plaUahl.ag is the responsibility of the TransmissionPlanning branch in the Generation and Transmission Planning Department.Planned major transmission works include lines to connect the projectedgenerating facilities at Rantambe, Samanalawewa and Trincomalee with the loadcenters. The former lines are expected to be 220-kV, while the major linesfrom Trincomalee are expected to be 400-kV. CEB also plans to extend andreinforce the 132-kV transmission system, and replace overloaded power trans-formers with larger ones at 132-kV substations.

Distribution

2.19 The planning of subtransmission and distribution projects hasrecently been strengthened by the establishment of the Distribution Develop-ment and Rehabilitation Branch (DDRB) of the Transmission and GenerationProject Department. The development of the subtransmission/distributionsystems has not kept pace with the rapidly increasing demand; consequentlylosses are excessively high, voltage drop often exceeds the original designlevels, and the number of outages has increased. The Project would addressthese issues.

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III. THE PROJECT

Project Setting

3.01 Electricity sales increased at the average annual rate of 7.8% duringthe period 1977-1985. Although this increase was matched by adequate expan-sion of CEB's generation and main transmission facilities, there was insuffi-cient investment in subtransmission and distribution facilities. Conse-quently, system development was not balanced, leading to increased systemlosses which, in 1985, were estimated at about 17% of gross generation. Itwas, in part, in the context of these losses that priority was accorded inGOSL's strategy (para 1.07) to improving the quality and reliability ofelectricity supply and the operating efficiency of the power system. Inkeeping with that objective, GOSL and CEB initiated a study in 1983(para 2.14) to identify the measures to reduce losses to economically accept-able levels. Following completion of the study, and in accordance with itsrecommendations, CEB established a group to formulate and implement a plan toreduce system losses. The group prepared a plan for the period 1985-1995 torehabilitate, reinforce and expand CEB's distribution system which is coor-dinated with planned expansion of generation capacity. The Project is afour-year time slice (mid 1987-mid 1990) of that plan and is based on aproject document 1/ prepared by CEB which identified an investment programfor mid 1987-mid 1990 that would maximize the economic benefits to be derivedfrom improving CEB's distribution system.

Project Objectives

3.02 The principal objectives of the Project are to: improve thereliability and quality of power supply; reduce technical losses; extend andreinforce the distribution system; and improve CEB's capability to constructand maintain its distribution system. In addition, the Project would assistCEB in developing a more appropriate balance between generation, transmissionand distribution facilities in order to meet the forecast demand at leastcost.

Project Description

3.03 The Project would consist of the following components:

(a) construction of about 250 km of double circuit and about 550 km ofsingle circuit 33-kV main distribution lines;

(b) construction of about 150 km of single circuit 33-kY lines, about 50km of single circuit 11-kV lines, and about 50 33-kV switching sta-tions; installation of about 50 MVAR of capacitors; and strengtheningand upgrading of about 500 km of 1l-kV lines;

1/ Distribution Development and Rehabilitation Proiect, Ceylon ElectricityBoard, October 1985.

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(c) installation of about 1,200 33-kV/LV and about 300 11-kV/LV distribu-tion transformer stations and transformers, and the conversion ofabout 200 km of LV lines to three phr e;

(d) construction of two 33-kV/11-kY and 125 11-kV/LV substations, theinstallation of about 15 km of 33-kV, 120 km of 11-kV and 125 km oflow-voltage cables for the underground network in the city ofColombo;

(e) line-materials, vehicles, tools and instruments, to rehabilitate thelow-voltage network; and

(f) consulting services for detailed engineering, project management,project accounting, training CEB staff in modern methods for theconstruction and maintenance of the distribution systems, andpreparation of a distribution master plan.

A detailed description of the Project is presented in Annex 3.1, and thegeographic area which it would cover is shown in Maps IBRD 19433R and 19434R.

Project Cost

3.04 The estimated total cost of the Project, including price and physicalcontingencies, duties and taxes, is US$108.1 million based on mid-1986prices. It comprises US$65.0 million in foreign exchange, US$16.0 million intaxes and duties, and US$27.1 million in local costs. Physical contingenciesof 10% are assumed for equipment, materials and services on the basis ofprevious experience with similar projects in the Region. Price contingenciesfor foreign costs are assumed at 7.0% for FY86 and FY87, 7.5% for FY88, 7.7%for FY89, 7.6% for FY90, and 4.5% thereafter. Price contingencies for localcosts are assumed at 10% for FY86 and FY87, 9% for FY88, 8% for FY89, 7.6%fcr FY90, and 4.5% thereafter. Total price contingencies amount to 18X ofbase costs including physical contingencies. A summary cost estimate ispresented in Table 3.1 and detailed estimates are given in Annex 3.2.

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Table 3.1Project Cost Estimate

Z ForeignLocal Foreign Total Local Foreign Total Exchange--- Rs million)-- ---(US$ million) --

Main 33-kV Lines 319.6 503.4 823.0 11.7 18.3 30.0 61Other MV Networks 137.4 260.3 397.7 5.0 9.5 14.5 65Rationalization of =LV Networks 101.8 104.4 206.2 2.7 3.8 7.5 51

Colombo City Network 216.8 270.8 487.6 7.9 9.9 17.8 56Rehabilitation ofLV Networks 73.0 131.9 204.9 2.7 4.8 7.5 64

Consultancy, Project -Management & Training 39.4 118.2 157.6 1.4 4.3 5.7 75

Total Baseline Costs 888.0 1,389.0 2,277.0 32.4 50.6 83.0 61

Physical Contingencies 88.8 138.9 227.7 3.2 5.1 8.3 61Price Contingencies 206.0 254.1 460.1 7.5 9.2 16.8 55

Total Project Costs 1,182.8 1,782.0 2,964.8 43.1 65.0 108.1 60==2========== ___= -==- S=-11== _

Project Financing

3.05 The financing requirements are US$43.1 million in local costs andUS$65 million in foreign exchange. Local costs would be financed by CEB frominternal sources (para 4.15). The foreign exchange cost of the Project wouldbe covered by the Association financing of US$52.0 million and cofinancing ofabout US$13.0 million by the Overseas Development Administration (ODA), UK.ODA has appraised the rehabilitation of the Colombo City network part of theProject and expects to present the project to its project comm'ttee byOctober 31, 1986, and to obtain Ministerial approval shortly thereafter.During negotiations, CEB presented a financing plan for the Project accept-able to the Association. Table 3.2 summarizes the financing plan.

Table 3.2Project Financing Plan(US$ million equivalent)

Local Foreign Total

IDA - 52.0 52.0ODA - 13.0 13.0CEB 43.1 - 43.1

Total 43.1 65.0 108.1

CEB would bear any cost overruns and GOSL would bear the foreign exchangerisk in accordance with the provision of the 1969 CEB Act. In order toensure that the Project is adequately financed in a timely manner, fulfill-ment of all conditions precedent to the effectiveness of the ODA Grant is acondition of Credit effectiveness (para 6.05(b)).

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Onlending terms

3.06 During negotiations, GOSL agreed to reLend the proceeds of the Creditto CEB under a subsidiary Loan agreement to be entered into between GOSL andCEB under terms and conditions acceptable to IDA. The term of onlendingwould be 20 years (including five years of grace) and at an annual interestrate of 10X. The conclusion of the Subsidiary Loan Agreement between GOSLand CEB, under terms and conditions acceptable to the Association, would be a-condition of Credit effectiveness (para 6.05(c)).

Project Engineering and Consulting Services

3.07 The Project has four components: (a) the expansion and reinforcementof the main 33-kY system and rehabilitation of the Colombo City distributionsystem; (b) ratior.alization and rehabilitation of CEB's MV and LV distribu-tion systems; (c) development and introduction of updated design standardsand construction guidelines for the distribution system; and (d) introductionof improved work methods and planning techniques for construction and main-tenance of the distribution system, and training of CEB's staff in the use ofthese methods and techniques. Implementation of these four components wouldbe a major undertaking for CEB as it exceeds in-house design, constructionand management capabilities for distribution projects. Consequently, CEBwould require considerable external assistance in project implementation andin the training and transfer of technology required to enable CEB to maintainand develop the distribution system in the future. CEB would, therefore,engage three separate organizations to provide consultancy services to assistin project implementation. The bidding documents for component (a) should beready by October 1986 to adhere to the project implementation schedule. Inaccordance with this schedule, in February 1986 CEB appointed Ewbank Preece,UK, who are presently engaged under the Seventh Power Project(Credit 1210-CE), to prepare these bidding documents and to provide engineer-ing services for component (a). IDA concurs with the appointment of EwbankPreece. The consulting services required for this purpose woulld amount toabout 30 manmonths, and their cost would be financed from the Credit. CEBhas also agreed to appoint consultants, satisfactory to IDA, to preparebidding documents for equipment and services required for components (b) and(c), and provide project management services for all four components. Thiswould require about 170 man months of consulting services, which would befinanced from the Credit. The appointment of consultants for preparation ofbidding documents, design standards, construction guidelines, and projectmanagement would be a condition of Credit effectiveness (para 6.05(d)). CEBhas also agreed to engage a utility (parg 3.08) to assist in the implementa-tion of component (d).

Project Implementation

3.08 CEB has limited experience in coordinating an extensive program forthe construction and rehabilitation of distribution networks. It would,therefore, be assisted by consultants in project management for all fourproject components (para 3.07). Project implementation within CEB would besupervised by DDRB under the Additional General Manager (Projects). DDRBwould supervise the work of the consultants, provide counterpart staff to betrained in the design and management of distribution projects and coordinateproject implementatioh within CEB. DDRB, which is at present inadequately

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staffed, is being strengthened in order to undertake these functions effec-tively. CEB has provided to IDA a satisfactory schedule for the addition ofqualified staff to DDRB. In order to expedite project implementation andfacilitate work coordination, supply and erect contracts -would be used,except for the rehabilitation of the LV network. CE8 would implementrehabilitation work under force account, since it is highly dispersed andinvolves close coordination with the operation of the existing distributionsystem. However, the planning, work methods and equipment presently used byCEB for construction and maintenance of the distribution system are inade-quate, and must be-improved to increase staff efficiency and productivity.In recognition of this situation, CEB has agreed to engage an operating powerutility, as consultants, to assist in the introduction of improved workmethods, equipment and planning techniques for the construction and main-tenance of the distribution system and to train CEB's force account staff intheir use. The appointment of consultants to assist CEB in the introductionof improved work methods and planning techniques for the construction andmaintenance of the distribution system would be a condition of effectivenessfor the Credit (para 6.05(e)).

3.09 The project implementation schedule is shown in Annex 3.3. Construc-tion of the Project would be completed by June 30, 1991. The Project invol-ves a large number of activities which would proceed concurrently. A majorportion of line construction would be through supply and erect contracts,which are expected to be won by contractors with adequate resources andexperience of similar work. The proposed schedule is, therefore, consideredto be realistic.

Procurement

3.10 The procurement of the various components of the Project- would bearranged as shown in Table 3.3. Procurement of equipment and works for themain 33-kV lines, MV network rationalization and rehabilitation of ColomboCity network would be grouped in several supply and erect contracts, and theother equipment and materials would be procured through supply contracts.All equipment and materials financed by IDA would be subject to ICB. As aresult, about 70% of the cost of works, goods and services fur the Projectwould be procured under ICB. Documents for individual contracts exceedingUS$200,000 would be subject to IDA's prior review and will apply to about 90%the estimated cost of IDA-financed elements. Local suppliers and manufac-turers competing for the supply of goods under ICB would have a preference of15% or the applicable customs duty, whichever is less. Consultants forproject engineering, project management and training would be selected andemployed in accordance with the Bank guidelines. Advance procurement andretroactive financing to cover expenditures in respect of consulting servicesincurred after January 1, 1986, and prior to Credit signing would be financedretroactively up to an amount of US$1.0 million equivalent. The plannedschedule for procurement of the equipment and material to be financed fromthe Credit is: (a) first bid invitation - November 1986; (b) first bid open-ing - February 1987; and (c) first award decision - June 1987.

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Table 3.3Procurement Arrangements

(Us$ millions)/a

Procurement Method /bICa LCB Ccher NA Total

1. Main 33-kV lines 38.6 - ^ 38.6(22.3) (22.3)

2. Other MV network, rationalization 19.3 - - 19.3(12.1) (12.1)

3. Rehabilitation of Colombo Citynetwork 23.2 23.2

4. Rationalization of LV development 10.0 - - 10.0networks - (6.2) (6.2)

5. Rehabilitation of LV network 4.8 - - 2.1 6.9(4.1) (4.1)

6. Vehicles, tools, instruments 2.6 2.6(1.8) (1.8)

7. Consultants, Training - 5.5 5.5(5.5) (5.5)

8. Administration 2.0 2.0Total 75.3 30.7 2.1 108.1

(46.5) (5.5) (52.0)

/a The figures in parenthesis are the respective amounts which wouldbe financed by IDA.

lb ICB - International competitive bidding.LCB - Local competitive bidding.Other - Direct negotiation or not subject to Commercial Procurement (e.g.

land acquisition, owner expenses). Rehabilitation of the ColomboCity network is expected to be financed by ODA (UK). Theprocurement of equipment and materials would probably be limitedto UK suppliers.N.A. - Force account.

Disbursements

3.11 Disbursements from the Credit would be made against 100% of foreignexpenditure or 100% of ex-factory price, if manufactured in Sri Lanka, of thecost of equipment, and materials and erection services procured under ICB,and 100% of the cost of consultancy. The estimated disbursements from theCredit are shown in Annex 3.4. In order to facilitate disbursements, aSpecial Project account would be established in a commercial bank in accord-ance with terms and conditions satisfactory to IDA. The initial deposit inthe Special Account would be US$5.00 million, representing the estimatedaverage expenditures for a four-month period for the items financed by theCredit. The proposed closing date for the Credit would be June 30, 1992 toallow for payment of retention monies. The disbursement profile for theProject is that for a four-year program to expand the rehabilitate CEB'sdistribution system. The Bank's standard disbursement profile for transmis-sion and distribution projects is not applicable to the Project, for tworeasons: firstly, the standard disbursement profile is predominantly

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weighted by projects involving the construction of extra high voltage trans-mission lines rather than the expansion and rehabilitation of distributionsystems; and, secondly, the Project would be implemented through a number ofcontracts proceeding in parallel.

Project Monitoring

3.12 CEB would submit quarterly progress reports covering the work ofconsultants, physical progress, project cost, disbursements and administra-tive aspects of the Project. In addition, it would also submit annual finan-cial and administrative reports and other pertinent information to IDA. CEBwould also undertake not later than six months after the closing date, orsuch later date as may be agreed for this purpose, to prepare and furnish toIDA a Project Completion Report of such scope and in such detail as IDA shallreasonably request, on the execution and initial operation of the Project,its costs and the benefits derived from it, the performance of CEB and theaccomplishment of the objectives of the Credit.

Ecological Effects

3.13 Most of the distribution lines included in the Project would beconstructed adjacent to public roadways and would be similar in visual impactto existing lines. The ecological impact of distribution lines is regulatedby Sri Lanka's existing laws, namely, Section 15 of the Electricity Act, TheFlora and Fauna Act, and the Forestry Ordinance. These laws adequatelyregulate any adverse ecological impact which could be associated with theconstruction of the Project.

Risk

3.14 The Project is straightforward and no unusual risks are foreseen.Delay in implementation is, however, possible since the project is spreadover a large geographical area and has many interfaces with the existingnetwork. This risk would be minimized through the provision of projectmanagement assistance by consultants. The packaging of the Project whichuses supply and erect contracts, and clearly identifies contractual respon-sibility, would also minimize this risk. Slippage could occur due to delaysin appointing contractors and problems in acquiring right of way. Any delaysin the appointment of contractors would be minimized by engaging consultantsprior to Credit effectiveness (paras 3.07 and 3.08). Most of the distribu-tion lines would be constructed adjacent to public roadways and Sri Lanka'sexisting laws give adequate powers to CEB to acquire right of way. Thus theacquisition of right of way is not expected to delay project implementation.

IV. FINANCES

Introduction

4.01 The financial activities of CEB are regulated by the provisions ofthe CEB Act of 1969 and the Finance Act of 1971. The CeBs Act requires theBoard to operate along commercial lines and ensure that revenues generatedfrom sales of electricity cover operating costs, including depreciation, debt

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service, and an adequate percentage of the cost of the development program.The Finance Act outlines procedures for the performance of audits and setsthe ceiling on the: remuneration of employees in the public sector(paras 2.07, 4.02, 4.04). In 1973 following the approval of the Fifth PowerProject (Credit 372-CE), CEB's statutory obligations were amended to allowdepreciation to be based on revalued assets. In 1980, under the Sixth PowerProject (Credit 1048-CE), an 8% rate of return on revalued assets was set asa financial objective for CEB.

Accounting Systems and Organization

4.02 In -1981, CEB engaged management consultants from the United Kingdom,Urwick International, under the Sixth Power Project <Credit 1048-CE) to set aframework for modern accounting systems and procedures to provide the basisfor better financial reporting and control (para 2.02). ImpLementation ofthe new systems and procedures, based on the consultants' recommendations,siarted in January 1984. Substantial progress has been made since then:accounting activities, with the exception of revenue accounting, wasdecentralized, billing automated, steps initiated to automate other areas ofaccounting and financial reporting, and an internal audit unit established(para 4.03). These changes have resulted in streamlined financial reportingprocedures and improved CEB's control over its finances by providing manage-ment with detailed and timely information for financial planning and control;however, despite these developments, their benefits have not been fullycaptured by CEB because of its inability to recruit and retain qualifiedaccountants due to the low salaries paid by CEB relative to the ceiling onremuneration set under the Finance Act of 1971 (para 2.07).

Audit Arrangements

4.03 Urwick International recommended (para 4.02) the establishment of aninternal audit unit in CEB to improve control over its finances. The unitwas established in 1984. Its manager, the Chief Internal Auditor, reportsdirectly to the Board of Directors. At that time, however, the unit wasinadequately staffed and, as a result, its activities were limited to revenueaudit. In 1985, CEB initiated steps to expand the unit's responsibilitiesand strengthen its staff to enhance financial control. These initiatives areexpected to provide CEB with a more effective management tool.

4.04 As with other public corporations, the external audit of CEB'saccounts is carried out by the Auditor General (AG) of Sri Lanka, under theFinance Act No. 38 of 1971 (para 4.01). The AG is an autonomous agency thatreports to the House of Representatives. As agreed under the Sixth Power(Credit 1048-CE) and Seventh Power (Credit 1210-CE) Projects, CEB has com-plied with the Bank Group Covenant for Audit by submitting its unaudited andaudited accounts to the Bank Group. Although the quality of audits wassatisfactory, there were often delays in the submission of CEB's accounts,primarily because of the inordinate time required for the finalization ofaccounts by CEB. The delays were caused by the complex reporting proceduresin the utility. In 1984, the Board restructured its organization and stream-lined its reporting procedures to improve management and control. As aresult, delays in the finalization of accounts were shortened significantly.The audit report for 1984 was two months late, mainly because of the time ittook to set the new procedures in place. The submission of audits in the

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future is expected to be timely because of CEB's efforts; for instance, CEBhas finalized and submitted to the Bank Group its unaudited 1985 accountswithin the covenanted four-month period. However, in order to ensureaccountability for resources used by the utility and compliance with theFinance Act of 1971 which the Association supports, the audit covenant agreedunder the Sixth Power Project (Credit 1048-CE) is repeated under the Project.CEB alreed during negotiations to submit to the Association its unauditedaccounts within four months from the end of the year under consideration, andaudited accounts accompanied by the Auditor's Report within ten months(Para 6.03(f)).

Fixed-Asset Accounting and Depreciation

4.05 CEB's fixed asset registers do not accurately reflect the value ofits plant and equipment. The value of some assets are understated relativeto their replacement cost because they are recorded in historical costs,while the value of other assets are overstated since unproductive assets havenot been written off. Furthermore, depreciation schedules are based onaverage rather than economic lives of assets. The management and operationof a modern power utility requires accurate knowledge of the assets employed,which also provide the basis for setting financial performance criteria forthe utility. In recognition of this, CEB engaged in 1985 under the SixthPower Project (Credit 1048-CE), Davidson & Associates (UK) as consultants toundertake a fixed asset accounting study. The study covers the physicalverification of CEB's assets, their classification into generation, transmis-sion, etc., and the establishment of suitable depreciation schedules. Thestudy would be completed by December 31, 1986. In order to ensure that:(i) the recommendations of the study are consistent with acceptable utilitypractices; and (ii) are implemented, CEB agreed during negotiations to:review the results and recommendations of the Fixed Asset Accounting Studywith the Association by March 31, 1987; and implement the agreed recommenda-tions by not later than July , 1987. (para 6.03(g)).

Insurance Arrangements

4.06 CEB bears its own insurance risks and for this purpose has estab-lished an insurance reserve. CEB makes an annual contribution of 1/10 of 1lof its revalued gross fixed assets, which is appropriated from net profit, tothe reserve. On December 31, 1984, the reserve had an accumulated balance ofabout Rs 78 million. However, this reserve has been used in the past topartly finance CEB's development program. If this practice continues, fundsearmarked for replacement of damaged plant and equipment could be depleted.In order to ensure that the funds accumulated are only used for replacementof damaged plant and equipment, the transfer of the balance in the insurancereserve accumulated as of December 31, 1985, to an escrow account with afinancial intermediary that could be utilized only in the event of damage toCEB's assets is a condition of Credit effectiveness (para 6.05(f). CEBagreed, during negotiations, that beginning fiscal year 1986, annual con-tributions to the insurance reserve would be deposited into the escrowaccount on the last day of the fiscal year (para 6.03(h)).

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Past Financia.l Performance

4.07 CEB's income statements, sources and applications of funds statementsand balance sheets are given in Annexes 4.1, 4.2 and 4.3, respectively, forthe years 1980-1985. The Board's operations for the years 1980-1985 werecharacterized by increase in gross generation (481), increase in state (474)0and substantial increases in average revenue per kWh (1262) due to tariffincreases of 1102, 421 and 632 in 1980, 1982 and 1985 respectively andincrease in revenues collected through the fuel adjustment charge. CEl'aoperating results for 1980-1985 are summarized in Table 4.1s

Table 4.1CEB's _Penrating Results, 1980-1985

1980 1981 1902 1983 1914 1985(Unaudited)

Generation (GWh) 1,668 1,872 2,066 2,114 ?l261 2t464Sales (GWh) 1,392 1,503 1,679 Y,792 1,877 2,061Losses (1) 17 20 19 15 17 16Ave. Tariff/kWh sold (Rs) 0.37 0.59 0.78 0.84 0.78 1.36

… -Rn ,wilIion---'-R

Operating Revenue /a 887 1,639 2,442 4,021 7,2i4 f,2uTOperating Expenses 557 1,081 1,628 3,190 1t444 I,:l1XOperating Income 330 558 814 831 81m ,fatiNet Income /b 303 495 436 205 436 1,26!4

Rate of Return onRevalued Assets (2) 9.4 11.4 8.d 5.6 i.t l0./Self-Financing Ratio (2) 68 72 24 ?1 16

/a Includes revenue from the fuel adiotlment charge,7b After interest a'td taxes.

4.08 CEB's gross generation of electricity incro dier 1r13m 1,660t CWM iar1980 to 2,464 CWh in 1985, reprenenting aOn 4vfrFgC aflnrlm.) VAt( s.f illt-iiulo f4about 82. Electricity saleo, aloo increaged at an dVwtapvL aiinail is.i- sftabout 8S, reflecting an unchanged love) ot Jonf.co, wtich tumnifir.tolt if l.Et,ihigh at about 17X over the 5-yenr peritstl, rP maly Merl;r( th[ OT114 h fo-ilf 5'i i i

CEB's investment program, particuilarly in dit ritotsii is.i dflvt)jtflW4if(para 3.01). CEO's operating revenuers iiecreiibed irsit.s Hti fsfil si*Mo, I itt ' 19Ito Rs 3,055 million in 1985, rppresentifg an aversosn Aritov4 ifltt 'f4 "I *1t11441Z. This wan primarily due to increauen in tariffn tssd ltw a.t ivat ui.n lotthe fuel adjustment charge. The fuel adJ%itMs.V Uflaihrgw 14nlItew ftst $iltrecovery of fuel cetnt ard the 1% llitsusitvm Ts4lsvisav-' To*,n $ott utr41 Ii't 1s li t5-year period, operating reventwst renchett n iim,tm 0 n 444l t'I ril)l ol# iin

lJ The RHninehn Ttvrnonr Tov* will ht ie ft e# It 7f i Ttp t

beginning 1986, ant emloftarA t1 12 l}titte flt, 1 6

-21-

sf>8} f.w* to *he recovery of the exceptionally high fuel cost and turnoverf-*x siFrirItfg tro Rs 2,507 million. The high fuel cost was caused by CEB'ssvio,roftl rreliance on thermal generation to compensate for the shortfall int,J4ereffeti^I preripitAted by poor hydrological conditions. Other operat-il, f.fitifs rffaiined at' a relatively reasonable level vis-a-vis the year before

s .q4fliw.fe tIy the fairly constant operating income to operating revenuesfitXf f Atf*4*t 352. Tor 198$, however, this ratio was 21X mainly because of aL'1OX icImteaSe in. Adminiotration costs, stemming from wage and salarytr'f f*t)ff. CFH's iteaniUre of financial performance, as agreed with the BankCif'"p" r*ivi at;IAfsftr tax minimum rate of return of 81 on revalued average neth ica A44APl i.n tso ipara 4.01), This rate of return was 9.4%, 11.4X andhtlt Of.r tha thfee yearo 1980, 1981 and 1982 respectively. For 1983,t:iv'wr, #th rrat- rIf repttrn. wan 5.61, due to the heavy income tax liability*!ijorl tft otiderertimWaed by CEB in setting its tariffs for that year. The4k* ,fl 1EJ)*w' npe ra'riz iteime after deducting a depreciation allowance of12.4t ftt *.P}41 faTwir1Gi6hfAŽ4 enonets (para 4.20), and based on straight linei mim'A *S A0- fitlilor aiietu. A tmaller depreciation expense for income tax

.V 1. 4z,. 4htoIrr tjy ttuit dr2lryn in the transfer of Mahaweli assets contrary tot¾*'i i 144tAtlm r' ffill(A4 in a lnrger taxable income and therefore in a

L';irs4' 'w iti-17ity vtihAr ror,imatfed for 1983. Excluding this tax liability,i tie tPe e4t 8 1i i8-}fi( t in 1983. Moreover, as result of the delays in

i.If.tfi 4 f t ta' "I stwi J u}tti ftrom 1983 as originally planned to 1984,litr 11fto-I t.'ei-u 0W) vinao bft bigpher than projected and, consequentlyt, the rate.|/1t,. * J th',. lUiawtitpgld occoontn for 1985 indicate that CEB has

fi.Ot, ',t.tt t,iJnoti,at $fotlif irwr-penetn sf1 110% in end-1980 and 42X inI * nr i i ; f-o,d i't,,*ty hillii l)evel of renource availability for

~e ~jh~ ~i~rj i(f? l.--rt 4.111). fluwever in those years, CEB's* 'J -' 1t h, i 5a,fpl.y tti e iii ii mnior generation projects were being

*, tt .. I,t t,f. J'twIli Ullit'r lnI A.MI (para 1.01) for transfer upon4 ('. 2t.fsi, 'st§t wfat i,ii renitidlctl it, hi,.h self-financing ratios of

.II ,, i X,##i l!,iat.Jft AQlfL ?Ifile,ofc%ivelyt, meanured ao the ratio of netw .tv t ti athi 1ivo dl(st'At, 1fit irivert mentn to average of investments4 4, 1 t.. *.i .i jf,sfidot Amr. rfoolcedi'i ytearr. In contrast, the underes-

t'J *m4nf i u 4! n i tllit y ift 1911-3 aid conecquent inadequate12 i '1'. 1 t..teii.tf. 14 4,4t-i t-Fi l illfrea n, reaulted in a lower

t If. tI 4i. 4 u t- $s, h1-1 I t Mo ftl { tt 4,018) In 19U4 and in 1985,1w,,+i..o *i $,[ft) 4i.8lttl '#144 f t of ?11K uitt 14%. - T'il e compnratively low

.,t .JI i.# 1 f i . ,it I. ll, d lot, v-t i -pto t he I ight of C.091hti prattice in, p li. 4'.f f I I.fi4.-4tf¶ ehl~t b t u' tJh,. IThe current practice is to1, . P .,, b ' i.nJ ¾).. [',2aiX Ij;'xlt t t) h' serhvnfl / equity or part

s t X t'A4 ' it4~'t "'4 d lt [¢t tuiff' )ftit et an} s r t nrLt of CE8'n inveot-. ,, , ,N etf 4 , 'mi ~f, 9 I t (l it} {.i tliit li ty'n inveujtmnent for

..4; $wt..N '. V.44., Is. .4i t3 , },j 1i CH'I, n investment,t,+ c -¶ tr :, 1; i~ isr I ti.' f- je** Jl}ftfl fiift 'I4li niro conqideredp the

:E i'' 4 .; V, I4 Xtt . i is il(i lS, t tXl '1f;0 t- ts

141

. s .r ~ 1 iu tuc~u */f' Pl:), ujIii trili" ja rniquired to

' ; ' ' 4 I ' .,........ ... k ' P 1, 4 'it l''44 .1 l4 1t t 4t-t.I1Ish uui7i IanM, up to and4 tS ;''. =*r.; . } i'F it +2 41f; t18 {l+}, } AAttogll C;t'g hat, made

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considerable efforts to meet that target, its accounts receivable have per-sistently exceeded the agreed level. Measured in terms of the equivalentnumber of months billings, receivables increased from 4.1 at December 31,1981 to 7.0 at June 30, 1983 and then declined to 6.3 at September 30, 1984and 5.4 at December 31, 1985. The three categories of consumers which wereresponsible for most of the accounts receivables as of December 31, 1985were: local authorities (40% of total accounts receivable and 11.6 months'billings); private consumers (37% of total accounts receivable and 4.1months' billings); and Government departments (9% of total accounts receiv-able and 7.9 months' billing). In 1985 CEB initiated a number of measures,including the implementation of a strict time schedule for billing and col-lection of revenue from high tension consumers and faster disconnection ofdefaulting private consumers, to reduce accounts receivable. In addition, inSeptember 1985 GOSL assumed responsibility for the payment of arrears andfuture accounts for street lighting; the accounts receivable for which hadexceeded 48 months in mid-1985 but have now been settled.

4.11 The persistent high level of accounts receivable from localauthorities has been addressed at the highest level of government, butwithout significant success until early 1986. The high accounts receivableare largely the result of their poor financial position, which is alsomanifested in the poor quality of electricity supply in their service areasbecause of underinvestment in their distribution systems. In some instanceslocal authorities utilize the monies collected from electricity sales fornon-power current expenditures, and in other cases, the principal problemconcerns inadequate collection from consumers as a result of billing disputesand consumer protests. The fastest way for the accounts receivables to bereduced to a satisfactory level would be for the Government to assume respon-sibility for their payment. However, this solution would not address theroot causes of the problem, which are related to the inefficiency of manylocal authorities in carrying out the function of electricity distributionand their poor quality of electricity supply. The long-term solution to thisproblem requires the reorganization of the power subsector with regard to thedistribution of electricity and upgrading the distribution systems which arenow operated by local authorities (para 2.05). GOSL initiated this with thecreation of LECO (para 2.04) which is to gradually take over localauthorities' distribution systems and rehabilitate them. The Bank Groupsupports this institutional reform which addresses the root causes of theaccounts receivable from local authorities. However, pending this long termsolution to the accounts receivable problem, as an interim measure in Decem-ber 1985, GOSL and CEB submitted to the Association a dated and monitorableaction program to reduce the Board's accounts receivable to three months'billing by September 1, 1987. During negotiations, CEB informed the Associa-tion that the action program has been substantially implemented, and thatoverall accounts receivable were 3.6 months' billing in May 1986. In orderto ensure that the accounts receivable would be reduced to covenanted levelsby September 1, 1987, COSL and CEB, during negotiations; areed to the fol-lowing monitoring targets for the critical consumer categories:i) reduction in receivables from local authorities to six months' billingsas a condition of Board presentation of the Project, five months' billings asa condition of Credit effectiveness, and three months' billings by Septem-ber 1, 1987; and (ii) from government departments and agencies (other thancorporations) to three months' billings by September 1, 1987. CEB also

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eed that beginning September 1, 1987, total accounts receivable would notexceed three months' billings (paras 6.02(a), 6.04 and 6.05(g)).

Present Financial Position

4.12 CER's balance sheets reflect fixed assets revalued as per agreementwith the Association under the Fifth Power Project (Credit 372-CE). A sum-mary of the methodology, including the indices used for the revaluation offixed assets, is given in the project file, and the proforma revaluation offixed assets for the years 1986 to 1995 based on forecast inflation indicesis given in Annex 4.7. CEB's balance sheet for 1985, the accounts for whichare being audited, is presented in Annex 4.3 and summarized in Table 4.2:

Table 4.2CEB's Balance Sheet (as of December 31, 1985)

(in Rs million)

As ̂Fs

Gross Fixed Assets 27,276Less: Accumulated Depreciation 6,306

Net Fixed Assets 20,970Work-in-Progress 1,800

22,770

Other Assets 83

Current Assets 4,987Less: Current Liabilities 1,156

3,831Total Assets 26,684

Equity and Liabilities

EquityGovernment of Sri Lanka 7,035Consumer Contributions 1,776Revaluation Surplus 8,931Retained Earnings 4,033Total Equity 21,775

Long-term Debt 4,909Total Equity and Liabilities 26,684

Debt/Equity Ratio 18/82

4.13 Government equity contribution, primarily in the form of transfer ofMahaweli assets (para 4.09) to CEB, increased from 141 of total equity as ofDecember 31, 1980 to 32% as of December 31, 1985 and was a major reason forthe Board's strong capitalization position with a debt/equity ratio of 18/82.In addition to the strong capitalization position, the coverage of debtservice by gross funds generated internally was satisfactory at 3.1.However, CEB's current ratio, the ratio of current assets to currentliabilities, is high at 4.3 because: the high accounts receivable of

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Rs 1,169 million, equivalent to 23% of current assets (paras 4.10 and 4.11)and the high level cash-on-hand of Rs 2444 million or 49Z of current assets.CEB recognizes that a large working capital requirement represents idle fundsthat do not contribute to improving its performance. Consequently# under theProject, CEB has prepared and implemented a dated and monitorable actionprogram to reduce and maintain the level of accounts receivable to threemonths' billings (para 4.11). CEBS has also initiated steps to utilize thecash-on-hand to finance part of the capital investment program (para 4.15).

Investment Program and Finan6ing-Plan

4.14 CEB's investment program for the period 1986-95 is presented inAnnex 4.5 and summarized in Table 4.3:

Table 4.3CEB's Investment Program 1986-1995

(In current prices)

(Z) ForeignRs Million US$ Million X Exchange

Ceneration 59,986 2,189 65 40Transmission 12,671 462 14 45Distribution 14,514 530 16 24Other 4,220 154 5 4Total 91,391 3,335 100 36

Expenditures to increase generation capacity would account for 65Z of theplanned investment, about 14% for extension and reinforcement of the trans-mission system, and about 16X for distribution. The remaining 5% would coverthe cost of the new training center (para 2.09) and other miscellaneouscapital expenditures. -The Association concurs with the size and mix of CEB'sinvestment plans. Traditionally, investment in development of the transmis-sion system account for about 20Z of the overall investment; however, in viewof the fact that over the past few years considerable investments have beenmade in transmission facilities, including those under the Sixth and SeventhPower Projects (Credits 1048-CE and 1210-CE), the proposed investment intransmission development is considered satisfactory in order to evacuatepower to the load centers. As for distribution, the planned investments arefor the extension and reinforcement of CEB's distribution systems and thus donot include the investments being made by LECO and local authorities. Never-theless, planned investment in distribution is considered to be satisfactorypending the preparation of the Master Plan for the optimal development of thedistribution systems (para 2.05).

4.15 Based on the above investment progrAm, a forecast sources andapplications of funds statement for the period 1986-1995 is shown inAnnex 4.2. The financing plan reflects the tariff increases required toenable it to meet the entire local cost requirement of Rs 40,788 million(US$1,488 million) over the 10-year period from funds generated internally.This is an objective set by CEB and agreed to by GOSL. The objective allowsCEB to take all necessary actions, including tariff increases, to ensure thatall local costs for the development program are met from internal sources.

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The foreign exchange requirement of Rs 50,603 million (US$1,847 million)would be financed through borrowings.

4.16 CEB's financing plan for the period 1986-1991, when the Project wouldbe implemented, is suimmarized in Table 4.4:

Table 4.4CEB's Financing Plan, 1986-1991

Rs million US$ million X

Requirements

Capital Investment -46,980 1*715 94Working Capital Increase 2,516 92 6Total Requirements 49,496 1,807 100

Sources

Internal Cash Generation 28,381 1,036Less: Debt Service 10,561 385Less: Income Tax 186 7Less: Insurance Escrow Account 456 17Net Internal Cash Generation 17,178 627 35Equity Contributions 5,904 215 12Other Contributions 2,396 87 5Borrowings:

Proposed IDA Credit 1,425 52 3Other Borrowings 22,593 824 45

Total Borrowings 24,018 876 48Total Sources 49,496 1,807 100

During this period, the requirement for funds would be Rs 49,496 million(US$1,807 million), consisting of Rs 46,980 million (US$1,715 million) forcapital investment and Rs 2,516 million (US$92 million) for increase inworking capital. CEB's capital investment includes an investment of Rs 4,500million (US$164 million) for Mahaweli facilities, although the actual invest-ment is being undertaken directly by GOSL (para 4.09). Of the total sourcesof funds, net internal cash generated from operations would contributeRs 17,178 million (US$627 million) while equity contributions by GOSL wouldbe Rs 5,904 million (US$215 million). GOSL's equity contributions wouldconsist of Rs 4,500 million (US$164 million) in the form of transfer ofMahaweli (Randenigala) assets and Rs 1,404 million (US$51 million) as afinancial contribution to the utility to implement Rural ElectrificationProject (para 4.17). Consumer contributions would amount to Rs 2,396 million(US$87 million). About 40X of the requirements would be met from internalsources (para 4.18) and about 121 from equity. Borrowings would finance thebalance 48Z, or Rs 24,018 million (US$876 million). Including the proposedIDA financing of Rs 1,425 million (US$52 million) , about Rs 6,185 million(US$225 million), or 26% of the required borrowings have been secured.Another Rs 8,312 million (US$303 million), or about 35% is likely to befinanced by the Bank Group and ADB for the proposed Trincomalee. Thermal

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Project and related transmission development, leaving a financing gap ofRe 9,521 million (US$348 million) representing 39t of the total financingrequirement. The financing gap would occur in the later years, particularly1989 and after, and GOSL and CEB are actively seeking to secure finances tobridge the gap. In view of CEB's and GOSL's recent success in securingsuppliers' credit and bilateral financing, the AMP being a case in point, itis expected that the resource gap would be closed in a timely manner toensure that the utility' s development program is implemented. In order toensure that Development Plan to be implemented is least cost and is ade-quately financed, CEB agreed during negotiations: (i) to annually review byDecember 31 of each year beginning with 1987, its long-term Power DevelopmentPlan with GOSL and the Association; and Uii) to take all necessary actions toimplement the plan resulting from such review (paras 6.03(i) and 6.03(j)).

Future Financial Performance

4.17 CEB's forecast income statements, sources and applications of fundsstatements and balance sheets for the period 1986-95 are shown inAnnexes 4.1, 4.2 and 4.3, respectively. In order to make CEB an autonomous,financially viable entity and to reduce its dependence on the national budgetfor capital investment, GOSL has agreed to CEB's self-imposed objective thatthe utility could take all necessary actions, including tariff increases, tomeet the entire local costs of its investment program from internal sourcesduring the forecast period, with the exception of local costs of the ADBfinanced Rural Electrification Project. This financial objective of CEB,which is supported by the Bank Group, would direct CEB's financial activitiesduring the forecast period. The forecasts through 1991 reflect averageannual tariff increases of about 10% in nominal terms, and assuming aprojected average annual rate of inflation of 7% for the period, the averageannual tariff increase would amount to about 3% in real terms. A summary offorecast operating results for the period 1986-91 is shown in Table 4.5:

Table 4.5Forecast Operating Results, 1986-1991

1986 1987 1988 1989 1990 1991

GWh Generated 2,815 3,071 3,34 3,648 3,975 4,334GWh Sold 2,308 21549 2,810 3,064 3,379 3,684Losses (Z) 18 17 16 16 15 15Average Tariff (Rs) 1.49 1.65 1.70 1.82 2.02 2.20Operating Revenues (Rs M) 3,878 4,714 5,544 6,803 8,451 9,504Operating Expenses (Rs M) 1,770 2,236 2,811 3,607 4,516 4,969Net Operating Income (Rs M) 2,077 2,323 2,733 3,196 3,935 4,534

Self-financing Ratio (Z) 30 40 33 48 39 37

Rate of Return (X) 9.10 8.1 8.1 8.1 8.3 8.1Debt/Equity Ratio (X) 16/84 18/82 21/79 24/76 29/71 32/68Debt Service Coverage Ratio 3.0 3.5 3.1 2.8 2.6 2.2

Revenue projections are based on (i) increases in electricity sales from2,308 GWh in 1986 to 3,684 GWh in 1991; (ii) increases in average tariff fromRs 1.49/kWh in 1986 to Rs 2.20/kWh in 1991; and (iii) a reduction in system

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losses from 18X of gross generation in 1986 to 15% in 1991. Forecast operat-ing expenses are based on normal hydrological conditions and on plannedsystem expansion. CEB's asset base will increase rapidly beginning 1986,because of the transfer of assets constructed under AMP (para 4.16) and itsown investment program (para 4.14). COSL concurs with CEB's self-imposedobjective of meeting all local costs of the development program from internalsources (para 4.15); however, in order to ensure that future changes to thisobjective do not result in the erosion of CEB's financial viability, thecovenant governing the financial performance of the Board (para 4.01) wouldbe repeated under the Project. Therefore, GOSL and CEB agreed during nego-tiations to take all necessary actions, including tariff increases, toachieve a minimum annual rate of return of 8% on the current value of averagenet fixed assets in use (para 6.02(b)).

4.18 The transfer of the Randenigala assets to CEB is expected to be madein 1986, the first year of the financial forecast. In keeping with theexisting practice of such transfers (para 4.09), these assets would be trans-ferred as equity, and their full cost (Rs 4,500 million) would be included inCEB's investment program for 1986. Despite the relatively large investmentprogram in 1986, CEB would achieve a self-financing ratio of 30% for theyear, primarily because of the full impact of tariff increases effected inMarch 1983. The self-financing ratio would remain at satisfactory levelsthereafter, as a result of the tariff increases required to enable CEB toachieve the 8% rate of return on revalued assets (para 4.17). In the years1987 to 1991, the ratio would annually average about 38%.

4.19 Forecast balance sheets (Annex 4.3) show that CEB's revalued(proforma) gross fixed assets are expected to increase from Rs 27,276 millionin 1985 to Rs 85,485 million in 1991. About 39% of the increase would befinanced from CEB's internal sources, about 10% from equity, and 51X fromborrowings. As a result, equity is expected to increase by about 160%, fromRs 21,775 million in 1985 to Rs 57,496 million in 1991. Long-term debt isprojected to increase by about 440Z from Rs 4,909 million to Rs 26,586 mil-lion, resulting in a deterioration of the debt/equity ratio from 18/82 in1985 to 32/68 in 1991, which is wholly satisfactory for a power utility ofCEB's size and functions. Both the ratio of current assets to currentliabilities and the debt service coverage ratio would continue to be satis-factory. However, because of the projected large increases in debt, CEB'sdebt servicing position should be monitored carefully. Therefore, in orderto ensure that CEBts debt service coverage by gross internal cash generationis satisfactory, CEB agreed during negotiations to consult the Associationbefore incurring new debt which would cause its gross internal cash gener-ation to fall below 1.5 times the debt service requirement (para 6.03(k)).

Invome Taxes

4.20 In April 1981, the basis for the calculation of annual depreciationallowances to determine tax liability was changed. This allows CEB to claiman annual depreciation allowance over an eight-year period of 12.5% on newlycommissioned assets, as compared to the previous allowance of 100% in thefirst year, and to carry fo ward any tax losses to subsequent years. Conse-quently, despite the proposed transfer of Randenigala (Mahaweli) assets in1986, CEB would be liable for the payment of the income tax in that year.The assets projected to be commissioned in 1987 are the transmission lines

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being financed under Credits 1048-CE and 1210-CE, and some distribution/ruralelectrification assets. The additions to the asset base in this year, there-fore, would be relatively small, thus making CEB liable for income tax.Thereafter, through 1995, because of its relatively large investment programand additions to asset base, the Board would not be Liable for income tax.

V. PROJECT JUSTIFICATION

A. Electricity Demand Forecast

5.01 Total electricity sales increased at the average annual rate of 6.0%in the period 1973-78, and 8.4% in the period 1918-85 (Annex 2.3). A sig-nificant change occurred in the percentage shares of -sales accounted for byCEB's major consumer groups in the latter period. Annex 2.3 shows that,comparing 1985 with 1975, there was an increase in the relative importance ofsales to residential consumers and a decrease in the shares of sales toindustrial consumers. The increase in sales during the period 1978-85 wasdriven by the increase in the number of new connections. The total number ofconsumers served by CEB increased at the average annual rate of about 16.0% ayear in 1978-85, representing a doubling of the number of consumers in lessthan five years.

5.02 The load forecast for the period 1985-95 is given in Table 5.1 andAnnex 2.6. Total energy sales are forecast to increase at 10.2% a year,while energy generated is forecast to increase by only 9.5% a year.

Table 5.1

Forecast Energy Sales by CEB, 1985-95

Average Annual1985 1995 Growth Rate

GN- X Z WU -

Residential 339 16.6 1,301 24.2 14.4Commercial 283 13.9 870 16.2 11.9Industrial 841 41.2 1,515 28.1 6.1Local authorities 499 24.4 1,228 22.8 9.4Street lighting 11 0.5 15 0.3 3.2Hotels 69 3.4 155 2.9 8.4Railway - - 300 5.6 s

2LQ4 100.0 5,384 100.0 10.2

Generation 2,464 5,384 9.5Losses 422 734Losses (Z) 17 12

The sales forecast allows for the effect on sales of the anticipated improve-ment in the reliability and quality of electricity supply associated with theProject. The Bank's general experience with loss reduction projects where

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technical losses are relatively high is that the reduction in losses isaccompanied by substantial increases in electricity sales. The load forecastalso reflects the projected continuing high rate of connections, whichaveraged about 39,100 a year in the period 1981-85 and is projected to beabout 41,200 a year in the period 1984-88. Significant changes are forecastto occur in the relative shares of sales to the major consumer groups servedby CEB. The major change concerns an increase from about 17Z to 24X of totalsales going to residential consumers and a decrease from about 41% to 28X forindustrial consumers.

B. Least Cost Alternative

5.03 CEB prepared the Project to reinforce and extend its subtransmissionand distribution systems to meet the forecast demand for electricity at leastcost. The assumptions used, methodology and results for each component ofthe Project have been reviewed and found to be satisfactory to IDA (seeproject file, Annex 6.1).

C. Economic Internal Rate of Return

5.04 Although the Project is expected to play a crucial role in theoptimal development and operation of CEB's supply system, its benefits toconsumers cannot be separated from those of other least cost generation,transmission and distribution development programs. In these circumstances,having established that the Project is part of the least cost expansionprogram, it is appropriate to carry out the cost-benefit analysis on theentire program to ensure that it is justified. For this purpose a"time-slice" of CEB's investment programs for generation, transmission anddistribution for the period 1986-2000 has been analyzed. Capital costs forthese programs, together with incremental fuel costs, are shown in Annex 5.1.All costs were expressed in terms of their equivalent border values. Aminimum measure of the benefits associated with these programs is given byincremental sales revenue. In early 1986, the average tariff revenue wasRs 1.51/kWh. CEB recoups the costs of thermal generation through a fueladjustment charge (para 4.08), which was set equal to zero in the averagetariff revenue of Rs 1.51/kWh. The rate of return analysis assumes that fuelcosts of thermal plants will continue to be recouped through the fuel adjust-ment charge. 1/ On this basis, the rate of return is estimated to be 9.0%(Annex 5.1).

5.05 The foregoing revenue-based measure of rate of return is, by itsnature, more a measure of the adequacy of tariffs than of the true economicmerit of the investment programs which include the Project. The estimatedrevenue-based rate of return of 9% is less than the estimated opportunitycost of capital of 10%, and this indicates that tariffs are currently lessthan long run marginal costs (para 1.05). In these circumstances, the

1/ Annual fuel costs for the period 1986-1995 were estimated using theWASP III planning model. The average fuel cost per kWh would be recoupedthrough the fuel adjustment charge. Consequently, the cost and revenueeffects of using thermal plants would exactly offset each other.

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Project will confer benefits in excess of those measured by incrementalrevenue.

5.06 A better measure of the rate of return can be obtained by estimatingconsumers' willingness to pay (WTP) for the incrementaltelectricity sales. Aconservative estimate of WTP was made as follows: for residential, commer-cial, street lighting, local authority and government consumers, it was theweighted average tariff rate for incremental consumption in the respectivetariff categories, while for industrial and hotel consumers, it was themarginal fuel cost of captive diesel plant (in 1984 these consumers had atotal installed capacity in excess of 26 MW). This gave a weighted averageWTP of Rs 2.44/kWh. On this basis the EIRR is estimated to be about lIZ.However, it should be stressed that this is only a partial measure of EIRR.The use of the weighted average tariff rates. for incremental consumption inall tariff categories with the exception of hotels and industry means thatWTP is underestimated since it generally excludes any measure of consumers'surplus. In addition, no allowance has been made for consumers' WTP for theimproved reliability and quality of electricity supply.

D. Justification for Bank Group Involvement

5.07 In addition to providing additional capacity to meet forecast loadgrowth at least cost, the Project will, through IDA'S involvement:

(a) improve the efficient use of resources by reducing system losses;

(b) assist GOSL in evolving an institutional framework in which the powersystem can be operated and maintained in an efficient and reliableway;

(c) rationalize the consumption of energy through the setting of tariffrates in relation to the costs to the economy of meeting consumers'demands for electricity; and

(d) provide training for CEB staff and work crews in methods for theefficient construction and maintenance of distribution systems.

VI. AGREEMENTS AND RECOMMENDATION

6.01 During negotiations, GOSL agreed to initiate, by October 31, 1988, aprogram satisfactory to the Association to rationalize the institutionalarrangements for the distribution of electricity in Sri Lanka (para 2.05).

6.02 During negotiations, GOSL and CEB agreed to:

(a) reduce the level of accounts receivable from local authorities andgovernment departments to three months' billings by September 1, 1987and, thereafter, ensure that total accounts receivable would notexceed three months' billings (para 4.11); and

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(b) take all necessary actions, including tariff increases, to achieve aminimum annual rate of return of 8X on the average current value ofnet fixed assets in use (para 4.17).

6.03 During negotiations, CEB agreed to:

(a) prepare and submit to the Association for its review by July 31,1988, a master plan for the development of distribution systems inSri Lanka (para 2.05);

(b) prepare -and submit to the Association by March 31, 1987, plannedstaffing levels and numbers for the period 1987-1989 (para 2.06);

(c) submit to the Association by June 30, 1987, and put into effect notlater than December 31, 1987, a scheme of incentives and a promotionpolicy based on merit and other appropriate factors (para 2.07);

(d) submit to the Association by November 30, 1986, the maintenanceprogram for its generating facilities for 1987 (para 2.13);

(e) employ consultants to review by December 31, 1987, plant maintenancesystems at the Sapugaskanda diesel power station and thereafterimplement the improvements recommended by the consultants accordingto a schedule acceptable to the Association (para 2.13);

(f) submit its unaudited accounts to the Association within four monthsof the end of the fiscal year, and audited accounts accompanied bythe auditor's report within ten months (para 4.04);

(g) review with the Association by March 31, 1987, the results and recom-mendations of the fixed asset accounting study, and implement theagreed recommendations not later than July 1, 1987 (para 4.05);

(h) deposit, beginning FY86, annual contributions to the insurancereserve in an escrow account with a financial intermediary on thelast day of the fiscal year (para 4.06);

(i) annually review its long-term Power Development Plan with GOSL andthe Association (para 4.16);

(j) take all necessary actions to implement the long-term Power Develop-ment Plan agreed between CEB, GOSL and the Association (para 4.16);and

(k) consult the Association before incurring new debt which would causeits gross internal cash generation to fall below 1.5 times the debtservice requirement (para 4.19).

6.04 The reduction of the level of accounts receivable from localauthorities to six months' billings (para 4.11) is a condition of Boardpresentation for the Project.

6.05 The following would be conditions of effectiveness of the Credit:

-32-

(a) completion by CEB of the restructuring of its organization, Asapproved by its Board of Directors in September 1982, and completionand distribution of related operationat and functional manuals (para2.03);

(b) fulfillment of all conditions precedent to the effectiveness of theODA Grant (para 3.05);

(c) conclusion of a Subsidiary Loan Agreement between GOSL and CEB underterms and conditions acceptable to the Association (para 3.06);

(d) appointment of consultants for detailed engineering, preparation ofdesign standards and construction guidelines, and project management(para 3.07);

(e) appointment of consultants to assist CEB in -the introduction ofimproved work methods and planning techniques for the constructionand maintenance of the distribution system (para 3.08);

(f) transfer of the balance in the insurance reserve accumulated as ofDecember 31, 1985 to an escrow account with a financial intermediarythat could be utilized only in the event of damage to CEB's assets(para 4.06); and

(g) reduction of the level of accounts receivable from local authoritiesto five months' billings (para 4.11).

6.06 Subject to the above conditions, the Project is suitable for theAssociation financing of SDR 43.2 million (US$52.0 million equivalent).

-33

POWR TX: DISTRIBUTION EXPANSION AND KFJILATIOII PRJrCT

Energy Sector OrganIzto (196

I~ ~ I

r~~~~~~ m Of U_powra&w v

I r sDSOhef PowwaEe

Eor~~~~

JF~~~DQ IWAI "NIAA O?

a _____1s_________II . L

VW s IDIw Lff*

i 'w -. )u.

5/S ;*RXINGGROUPS

---- onICorsuiumo or . 1

SRI LANKA


Ceylon Electricity Board - Organization Chart

l l

I I

OM . l l

o A _ww em *-u 'slo'Aw

_ C_ a.P _ _ dow - KO_C4Vp 9- -MW awwT.f P>_S Pbo_ 9 _ 90soo - fto

9v _ Po_ P -V--s - ee$s To. =dbLo S

P9~ LS eaz - P GM

_a M- v SIGMQl p~S~o, G-o %W.

po -k ftD SkW. _8F

DS 9~~~~~P."

-Um<&xbmP0.0 %vr

_ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~x

-35-

ANNEX 2.2

SRI LANKA

POWER IX: DTSTRIBUTTON EXPANSION AND REHABILITATION PROJECT

Details of Generation and Plt_ CapaCitieS 1975-1985

1975 IIE 19i7 ini M m ML 1m 1982 1I 98 emi

Oenerrtion Details tMM)

Lakeapana 223 216 236 243 262 272 272 259 160 330 278 230New Lakeapana 387 376 364 381 470 468 510 505 406 436 457 434Wisialasurendra 86 71 86 112 112 97 97 111 58 146 152 103Smaonala (Polpitia) 353 313 328 389 399 410 416 407 287 432 368 373lnginiyagala 18 28 8 22 17 29 10 10 16 42 30 21Udavelave 10 8 7 12 8 8 9 9 5 16 14 11Ukuvele 97 186 207 193 195 200 207 146 265 201 189Dopatenne 57 100 60 166 99 96Canyon 79 147 120 115Victoria 89 586 -

Kotuale………… - -- -

Total Hydro 1,077 1,109 1,215 1,366 1,461 1,479 1,571 1,608 1,217 2,091 2,395

krmal

steoa: Ielanitiece 1 24 2 14 58 140 98 89 147 11 - 53Diesel: Pettab 1 2 12 7 5 7 2 5

Chunnakam 4 5 19 13 11 8 1 - 9Sapugaskande 39 60 -

Gas Turbine: Kelanitiaos _- _.J __l 18. 183 3S 3Z1 9 236

Total Thermal 1 24 2 19 65 189 301 *58 897 170 69

Total Gneeration (GIh) 1,078 .133 1,217 1,385 1,526 1,6S8 1,872 2,066 2,114 2,261 2,464

Cagacity I)ettkll (IN)iXdro (M)

Lakoapana (308.33+12.5) 50 50 50 50 50 50 50 50 50(50) 50( 50) 50( 50)New Lakespana (2x50) 100 100 100 100 100 100 100 100 100(50) 100(100) 100(100)Viaelasurendre (2x25) 50 50 50 50 50 50 50 50 50(25) 50( 25) 50( 25)Saoaala (Polpitia) 75 75 75 75 75 75 75 75 75(75) 75( 75) 75( 75)

(2437.5)Inginijasals (2%2+2x3) 10 10 10 10 10 10 10 10 10(-) 10( - ) 11( - )Udavalae (3:2) 6 6 6 6 6 6 6 6 6(-) 6( -) 6(-)Ukwel (2x20) 40 40 40 40 40 40 40 40(40) 40( 40) 40( 40)Novatenne (OIM3) 38 38 38(38) 38( 38) 40( 38)Canyon (1l30) 3030) 30C 30) 30( 30)Victoria (3:70) 70( 70) 210(210)Koteale (3x67 final) _ ( )

Total Hydro 291 331 331 331 331 331 369 369 399(308) 469(428) 679(568)

Therml

Steam: elanitisas (2x25) 50 50 50 50 50 50 50 50 50(25) 50( 25) 50( -Diesel: Pettab (23) 6 6 6 6 6 6 6 6 6(6) 6( 6) 6( -)

Cbunnakam (5%2+4xl) 14 14 14 14 14 14 14 14 14(14) 14( 14) 14( -Sapugaskand (4x20) 60( 40) 80( 60)

Gas Turbine: Kelanitiaes (6x20) __ I_ n 20 80 u 120(80) 120(100) 120Q00

Total Thermal 70 70 70 70 70 90 150 190 190(125) 250(185) 270(li0

TOTAL CAPACIT! (MI) 361 40; 401 401 401k 421 519 559 589(423) 719(613) 949(7:8)

|g: Figures it pareutbesia are effective cpacity.

7-7-.w.'. => 'L ' TANSION' AND REHABILITATION PROJuCT

Z.erz- a^.d Capacite- Balances 1975-1985

Growth Rate~ 19Th 197 3976 19?9 9lW 1911 1 2 S b.. Aed

3e*ieu2ial 8?7 5 07 110 353 391 217 258 305 316 39 14.6~r~*'tia1I U9 335 I" 154 201 223 220 235 244 241 283 9.1

tu*tria 523 317 520 597 632 626 678 739 752 791 061 4.9Uoca1 fttwittes 2a 23? 252 27M' 296 335 31 416 433 458 499 8.4Stve Lititsj 33 13 14 IS 16 17 6 9 10 11 11 -acel0 - - - _ - - _ 27 _.1 I __ -

Total Sales 965 997 1,041 1,161 1,298 1,392 1,503 1,606 1,792 1,876 2,042 7.8

NetVlu 107 129 170 214 219 259 352 363 301 374 411 14.4Station s Y 7 6 _ 10 1 8 17 21 _I I it

Total aes 113 136 176 224 228 277 369 380 322 385 422 14.1

Rair Geatationtae$ plus 3.oes. 1.078 1,133 13217 1,385 1.526 1,668 1.872 2,066 2,114 2,261 2,464

bua1id by Laeydt 1,077 3,109 1,215 1,366 1.461 1,479 1,571 1,608 1,217 2,091 2,3ffrbemal 1 24 2 19 65 189 301 558 1SW 170 69

1od fact:or () 56 54 53 54 53 52 52 55 55 53 55

1. Cmitw Rul. Lw)X-mims V40qA 219 240 261 291 329 369 413 431 437 47 515S

,stalld (Iffective)

37*. 291 331 331 331 331 331 369 369 399(308) 469(426) 679(366)Ibemal _ .......a jj tO .j~..7 70 70 _. __0 _1 .(125) __5(185) U(160)

Total 361 401 401 401 401 421 519 589 589(433) 719(613) 949(728)

Cpcity, installed(effective) W 142 161 140 110 72 52 106 126 152(-14) 232(112) 431(213)

Capacity, 2 of installed(effective) 39 40 35 27 18 12 20 23 26(- 3) 32( 21) 46(29)

r or Eetailu see bAn 2/2

SRI LANKA


Number of Consumers and Revenue 1975-1985

Nigh XediUM sad Local Street Total AverageResidential CoeecjAl VoltafLe Lo Voltase Authorities Lishtina Total Rs Milli" & &AkY La1975 81,674 20,957 55 2,911 218 219 106,034 155.6 0.161976 89,753 22,372 56 2,207 218 246 114,852 162.4 0.161977 97,998 24,311 56 3,246 218 249 126,078 172.2 0.161978 113,017 26,712 61 3,575 218 277 143,860 203.0 0.171979 142,224 31,408 61 3,817 218 323 178,051 388.3 0.301980 167,991 34,869 61 4,411 218 325 207,875 839.6 0.601981 195,025 37,839 63 5,239 218 319 238,703 1,509.3 1.001982 227,857 41,510 70 6,052 218 353 276,060 2,523.6 1.491983 259,687 44,440 73 6,419 218 358 311,195 2,794.5 1.561984 301,483 48,538 75 6,959 218 358 357,631 3,111.5 1.651985 (prov.) 336,294 50,833 80 7,289 218 358 395,072 3,151.2 1.53Growth Rate

Average p.a. 15.2 9.3 3.6 9.6 - 5.04 14.06

/a Includes revenue from fuel adjustment charge.

ANflI2.25

- -38-

SRI LANA


CE)tS Least Cost Generation Expansion Plan 1986-2000

1986

*1987 - Canyon Unit 2, -30 MW, Raudenigala 1 & 2, -122 MW, (hydro)

*1988 - Kotuale Unit 3, -67 MW (hydro)

1989 - Kelanitissa Recommissioning, - 50 MW (thermal)

1990 - Rantambe, - 49 MW (bydro)

1991 - Samanalaweva, - 120 MW (hydro)

1992 - Broadlands, - 20 MW (hydro)

1993 - Coal - 150 MW, Ist Unit

1994 -

1995 - Coal - 150 MW, 2nd Unit

1996 -

1997 - Coal - 300 NW, 1st Unit

1998 - Upper Kotmale, -240 MW (hydro)

1999 - Kukule, -180 MW (hydro)

2000 - Coal - 300 MW, 2nd Unit

* Committed projects

SRI LANKA


Forecast Energy and Capacity Balances 1985-1995

Gmoth Rate

19 0 i 5 1989 19 89 122Q Jlt2 19 * 11.4 -- 12A ve

A. nerctv 11lance (GWb)

Residential 349 413 492 5t6 645 728 822 929 1,050 1,190 1,301 14.4Ca uercil 283 343 381 422 457 521 S78 642 712 783 870 11.9Industrial 841 929 910 1,040 1,0" 1.156 1,223 1,292 1.362 1,435 1,515 6.1Localauthorities set It 499 521 573 630 675 761 832 924 1,016 1,110 1,228 9.4Street LightinS 11 11 12 12 13 13 13 14 14 15 is -Mlotels 69 91 110 120 125 130 135 140 145 150 1S5 8.4RaiZvsy -_ 50 ?0 81 125 __1 2300 _

total Sale 2,042 2,308 2,548 2,810 3,064 3,379 3,684 4,066 4,432 4,943 5,384 10.2

S of geueration 18 18 17 16 16 1S 15 14 14 '12 12 -G0b 422 507 523 535 584 596 650 662 721 674 734 -Rlauired Generation (Cub)salesplus losses 2,464 2,815 3,071 3,345 3,648 3,975 4,334 4,728 5,153 5,617 6,118 9.5Sktn2133

y7dto 2,395 2,661 2,980 3,08D 3,080 3,28 3,710 3,805 34205 3,805 3,8DS _Thermal 69 154 91 265 568 687 624 923 1,348 1,812 2,313l ers.lg . 55 54 54 54 54 S4 54 54 54 54 54 -

8. Canacit, 3alsace (33)5s1 595 649 707 771 840 916 996 1,086 1,187 1,293 9.6lnetalled (effective)

capacity8Rydro 679 727 879 946 946 996 1,116 1,146 1.146 1,146 1,146Thermal 20 _200 200 200 250 250 _2S 250 LM -- 0m .4__

Total 949(728) 927(703) 1,079(989) 1,14(1,056) 1,196l(,101) 1,246(1,151) 1,366(1,271) 1,396(1,301) 1,S4f6f,326) 1,546(1,326) 1.696(1,476)Pl nt Xri

Capecity 2 of in4t5lled(effective) 46 (29) 25 (15) 40 (34) 38 (33) 36 (30) 33 (27) 33(208) 29 (S) 30 (18) 23 (10) 24 (12)

-40- ANNEX 3.1

SRI LANKA

POWER IX: DISTRIBUTION1 EXPANSION AND'REHABILITATION PROJECT

Project Description-

The project consists of the following components:

(a) Development of MV Network (See Attachment)

33 kV lines Double circuit 0.175 in.sq. conductor 250 km33 kV lines Single circuit 0.175 in.sq. conductor 550 km33 kV lines Single circuit 0.075 in.sq. conductor 150 km11 kV lines Single circuit 0.075 in.sq. conductor 50 kmConversion of 11 kV lines to 33 kY SOO kmReconducting of 11 kV ad 33 kV lines

using 0.075 in in.sq. conductor 25 kmCapacitors and associated equipment 50 MVAR33 kV switching facilitiesReclosers/Sectionalizers 200Switch tfses/Loadbreak units 150Gantry arrangements/Busbars 50

(b) Rationalization of LV Development

33 kV/LT distribution substations lt20011 kV/LT distribution substations 300LT line conversion to 3 phase 200 km

(c) Augmentation of Colombo City Network

33 kV/l1 kV substation 233 kV cable 15 km11 kY cable 120 km11 kV and LT substations 12511 kV switchgear 130LV cable 125LV feeder pillar 100Isolating boxes and LV switchgear as necessary

(d) Material, such as connectors, etc. required for LV distribution systemrehabilitation for overhead lines and substations.

(e) Consultants for detailed engineering, project management, project account-ing, communication system study and development of distribution masterplan. Approximately 470 manmonths.

(f) Training of CEB staff in modern methods of distribution construction andmaintenance by associating a utility.

(g) Tools, instruments and vehicles.

-41-

ANNEX 3.1AttacbmentPage I of 6

SRI LANKA


Project Description

Division. Southern

Double Single SingleCircuit Circuit Circuit

.175 in.s. .175 in.sg. .075 in.sq.

1. Galle Grid SS 1/ to Natara via Weligama 33.0

2. Galle Grid SS to Wanduramba 1i.03. Proposed Embilipitiya Grid SB to Nonagama gantry 28.04. Connections of the existing lines to the proposed

Embilipitiya Grid S5 10.05. Smbilipitiya Grid SS to Mahar8 Primary SS via

Sevanagala Sugar Cane Factory - - 21.0TOTAL 33.0 40.0 31.0

Conversion of 11 kV to 33 kV

6. 11 kV networks fed off Nihiluwa Primary SS 50.07. 11 kV networks in inland area fed off Gonapinuwala

Nindana and Kurundugahatekms Primary SS 35.0TOTAL 85.0

I/ SS = Substation.

-42-

ANNEX 3.1AttachmentPage 2 of 6

Division: Eastern


.175 in.sq, .175 in.sq. .075 in.sq.

1. Inginiyagala Grid SS 1/ to Ampara 21.0

2. Inginiyagala Grid SS to Ampara 24.03. Ampara to Chandayantalawa proposed gantry 14.04. Proposed Chandayantalawa gantry to proposed

Vellaveli gantry 13.05. Second circuit on 0.075 in.sq. from Vellaveii

to Periyaporative 6.56. SC lines to 0.075 in.sq. from Ampara to Karanagawa 4.57. One SC 0.075 in.sq. line to be constructed for

reliability link shown in the map 2.5TOTAL 72.0 13.5


8. 11 kV networks fed off Weeragoda Primary SS 83.09. 11 kV networks fed off Hinguarana Primary SS 20.0

TOTAL 103.0

1/ SS = Substation.

-43-

ANNEX 3.1AttachmentPsge 3 of 6

Division: Western


.175 in.sq. .175 in.sq. .075 in.sq.

1. Matugama Grid SS 1/ to Fullerton Primary SS 13.0

2. Matugama Grid SS to Bentota Primary SS 15.03. Matugama Grid to Welipenna 7.04. Welipenna to Bellana 12.05. Ratmalana Grid SS to Maiokkawatta 6.06. Maiokkawatta to Modara 6.07. Modara to proposed Panadura Grid SS 6.08. Connections to the existing lines from the

proposed Panadura Grid SS 4.09. Proposed Panadura Grid SS to Horana 18.010. Proposed Avissawella Grid SS to Ruwanwella 19.011. Proposed Avissawella Grid SS to Padukka 15.012. Padukka to Makumbura 13.013. Proposed Avissawella Grid SS to Eheliyagoda 18.014. Balangoda to Ratnapura 36.015. Pannipitiya Grid SS to Makumbura 5.016. Pannipitiya Grid SS to Arangala 7.017. Arangala to Mulleriyawa 5.018. Mulleriyawa to Ethul-Kotte 5.019. Kolonnaws Kalubowila Aththidiya to Maliban gantry 14.020. Welipenna to Magala 13.2

TOTAL 71.0 153.0 13.2


21. 11 kV lines fed off Amabatale Primary SS 28.022. 11 kV lines fed off Ethul-Kotte Primary SS 20.023. 11 kV lines fed off Pelawatta Boralesgamuwa and

Nawinna Primary SS 17.0TOTAL 65.0

1/ SS Substation.

-44-

ANKEU 3AttachmentPage 4 of 6

Division: Northern

Single SingleCircuit Circuit

.175 in.sg. .075 in.sq.

1. Chunnakam Grid SS I1 to proposed Vadukkoddai Gantry 7.0

2. Connections to the existing lines from the proposed

Vadukkoddai Gantry 3.03. Chunnak*m Grid SS to Katirippai 11.0

4. Anamaduwa to Nawagaththegama 19.0

5. Galgamuwa to Potana-Sivambalava 11.5

6. Calewela to Dambulla 11.5

7. Nalanda to Ukuwela feeder 6.0

8. Yakalla to Galoya 20*0

TOTAL 21.0 68.0

/ SS s Substation.

-45-

ANNEX 3.1AttachmentPage 5 of 6

Division: CentralDouble single SingleCircuit Circuit Circuit

.175 in.sq. .175 in.ogq .075 in.sq.

1. Ukuwela Grid SS I/ to Natale 11.0

2. Ukuwela Grid SS to Narandanda proposed gantry 8.03. Connections from proposed Narandanda gantry to

existing lines 2.04. Proposed Narandanda to proposed Kundasale gantry 9.05. Proposed Kundasale gantry to Putuhapuva 10.06. Proposed-Kundasale gantry to proposed Bogambara gantry 7.07. Connections from the proposed gantry at Kundasale

to the existing lines 2.08. Proposed Kandy Grid SS to proposed Bogambara gant 8.09. Proposed Kandy Grid SS to Manawella 16.010. Nsnawella to Kegalla 14.011. Proposed Kandy Grid SS to Ulapane 23.012. Ulapane to Norton Bridge Grid SS 27.013. Connections from the proposed Kandy Grid SS to

the existing lines 4.014. Thulhiriya Grid SS to proposed gantry at Giriulla 13.015. Proposed Giriulla gantry to Pannala 13.016. Proposed Giriulla gantry to Kuliyapitiya 20.017. Thulhiriya Grid SS to Dewalegama (Kegalla) to

replace proposed 0.075 in.sq. line under Tr. 4 12.518. Wimalasurendra Grid 3S to Hatton 11.419. Wimalasurendra Grid SS to Naskeliya 10.720. Nuvara-Sliya Grid SS to Bandarawela 26.521. Badulla Grid SS to Bandarawela 20.122. Ambepussa (Ambepussa is on spur line off

Nittambuva-Nirigama line) to Warakapola 4.023. Proposed Matale gantry to Aluvihara Primary SS 5.024. Proposed Hatton gantry to Lindula gantry 9.025. Proposed Hatton gantry to Bakindale 2.026. Reconductor spur line off Kandalama from

7/.102 to 7/.161 5.0TOTAL 66.0 202.2 25.0

11 SS t Substation.

-46-

AMNEX 3.1AttachmentPage 6 of 6

Divisiont North WesternDouble Single SingleCircuit Circuit Circuit

.175 ag.in. .175 sg.in. .175 sg.it.

1. Kelanitissa switching station to Waragods Primary SS Il 3.0

2. Waragoda Primary SS to Enderamulla gantry 5.03. Biyagama Grid 8S to gantry at Imbulgoda via

Mawaramandiya Primary SS 9.04. Proposed Iabulgoda gantry to GCmpaha 10.0S. Biyag.ma Grid SS to proposed Anniyakanda gantry-via -

Enderamulla gantry 14.06. Kotugoda Grid SS to Veyangoda N.T.C. 16.07. Kotugoda Crid SS to Campaha 12.08. Kotugoda Grid SS to proposed gantry to Me-Eliya 4.09. Proposed Ma-Eliya gantry to proposed Aniyakanda gantry 6.010. Proposed Ka-Eliya gantry to Ja-ela area (two SC) 2.011. Kotugoda Grid SS to proposed Katunayake gantry 7.012. F.T.Z. Primary SB connection to proposed Katunayake gantry13. Kotugoda Crid SS to Seeduwa 6.014. Bolawatta Grid SS to Negombo Primary SS via proposed

Periyamulla gantry 11.015. Proposed Periyamulla gantry to Periyamulla Primary 8S 1.016. Proposed Madampe Grid SS to Iranawila (Voice of

America Radio Station) 6.017. SCO. 175 in.sq. lines to Chilaw and Dummalasuriya

from the proposed Madampe Grid SS 11.018. Dummulasuriya to Kuliyapitiya 16.519. Two SC lines to feed the proposed Ja-8la and Wattala

Primary SS 2.420. Five SC lines to be constructed for reliability link

as shown in the maps 13.8TOTAL 73.0 68.S 16.2


21. Parana Ambalams feeder fed off proposed Wattala Primary SS22. Poththode feeder fed off Negombo Primary SS 5.723. Kadawatha and Biyagama feeder fed off Waragoda Primary SS24. 11-kV networks fed off Andiambalama Veyangoda,

Nittambuwa, Miriawatta, Mawaramandiya andRamaga Primary SS 176.0TOTAL 21 6 8

1/ SS - Substation.

SRI LANKA


Detailed Cost Estimate(US$ Million)

loeBase :osts %sical Contingencies Price Contirnecies total Incl. Cent. Phlsical Costs +----------------------------- ----- ------ - --- Cont. Plus Price

Local Local Local Local Price Cont. Cant. ongo:. (E;cl. Duties t For, (Excl. Duties S For. (Excl. Duties I For. (Excl. Duties I on Phssical BasE-ch Taxes) Ta;;es Total Exch. Taxes) Taxes Total Exch. Taxes) Taxes Total Exch. Tars) Taxms Total Cnt. costs

:. .ZTSTENT COSTS

' :NE 23N385TrJ, :ON hlNP EEHADILTAT10N 23.3 7.4 7?5 38.2 2.3 0.7 O.B 3.8 4.1 I's 1.4 7.3 29.8 9.9 9.7 49.4 4.5 44.95 NVRibERSIOe OF .; D' FEEMRS 'C 23 XV 2.3 0.7 0.4 3.4 0.2 0.1 0.0 0.3 0.5 0.2 0.1 0.8 3.0 1.0 0.5 4.5 0.4 4.1

C. SUaBThTI2NT1a ADS1TITVEAR 11,0 2,0 2.2 15.2 1i1 0.2 0.2 1.5 2.2 0.5 0.5 3.2 14.4 2.7 2.9 19.9 1.8 18.1D. tA;BE 5,8 6.1 0.6 12.5 0.6 0.6 0.1 1.2 1.0 1.5 0.1 2.6 7.4 8.2 08 16.4 1.S 14.9E. DISTR:KBT IN TF8NSF0RNERS 2.4 2.4 1.2 5.9 0.2 0.2 0.1 0.6 0.5 0.7 0.3 1.4 3.1 3.3 1.6 7.9 0.7 7.2: VEHICLES TOLS AND INSTRUNENTS 1.5 0.1 0.5 2.1 0.2 0.0 0.0 0.2 0.2 0.0 0.1 0.2 1.9 0.1 0.6 2.6 0.2 2.3ELGINEEERING A PROJECT HANABENENT 4.3 1.4 - 5.8 0.4 0.1 - 0.6 0.9 0.4 - 1.2 5.S 1.S - 7.5 0.7 6.8

.. iESTMEhNT COSTS 50.7 20.1 12.3 83.1 5.1 2.0 1.2 8.3 9.3 5.1 2.5 16. 65.0 27.1 16.0 108.2 9.8 98.450.7 20.1 12.3 83.1 5.1 2.0 1,? 8.3 9.3 5.1 2.5 16.8 65.0 27.1 16.0 100.2 9.9 98.4

3et-etaber 17s 19S6 10:36

t-

o0 vI-

.a

44

~~ ~ft S SOC t ~~~~ 3 t; Asr* .- i s ' ilF *zi - . - -. -3 .-fl t tA4 ra wt. ' 4Nt; so -, . 9 s. s. w

s _ t I tt ~-,x "'

_ i i*J* 4~ r_0.s ~>_4 et -~#

* * Lo -tr 3 * 3i w .'>t _rt ;ru, , a- X4 -e 1 * _ _ *OM * Ai.

R '*tt ?S_sXib Ctt *-~?Z .t_..- . 2 .. ~t Z. ;l -) : .Sa t.tL :-F 4Z .tt_

ar1 2. t P v X _ ?- ' a; > g. - 4_,w-c_.n - ' a- * *

4W "i. n._ m;S j .a n ,'=c-. a r aeC- n: rrt .-zf I / - m- ' * .+a

4W _ * I_ 'I st -- - - - -'------' -- - - -

~~- zat t t l~Za- a _ ;

~~~~~-~~~~~~~~~~~~~ ~ -- .-:~ - . -_-

SRI LANKA


Summary Account by Project Component(SL Rs Million)

COSULTAY PhasicalCOLONSB PROJECT Continsencies

NAIN 33 ;r OTHER W PiTIONALIZhlATIN OF CITY NETUORK 0NEMENT -NDUINES NETWORKS LY NETORKS NETYDRK REHAIUTAION TRAININO Total ; Amwnt

I. INVESTWN COSTS

A. LINE COSITTION AND ROEAdILITATION 8123.0 v77,3 - 147.0 - I1,47.8 10.0 104.8. CON IN OF 1 KFEV ERS TO 33 K - 89.2 4.9 - - 94.1 10.0 9.4C. SUBSTATIUNS Mm SMITOCHEM - 184 2 85A4 146.1 - 415.7 10.0 41.6D. C E - - - 341.5 - 341.5 10.0 34.2E. DISTRIrIION TR2N0RS - 46.5 115.9 - - - 162.4 10.0 16.2F. VEHICLES TOOLS AND INST ENTS - - - - 57.9 - 57.9 10.0 5.8S. EINEERI6N MID PROJECT WEI - - - - - 157.6 157.6 10.0 15.8

Total INVESTlNT COSTS 823.0 397.7 206.2 487.6 204.9 157.6 2.277.0 10.0 227.7Total 1ASELECOSTS a23.0 397,7 206.2 487.6 204.9 157.6 2,277.0 10.0 227.7

Physical Contingencies 82.3 39.8 20.6 4848 20.5 15.8 227.7 0.0 0.0Price Contingencies 155.4 91.9 47.0 100.0 33,9 31.9 460.1 9.1 41.8

Total PROJECT COSTS 1i060,7 529,4 273.8 636.3 259.3 205.2 2,964.8 9.1 269.5

Taxes 233.4 75.2 49.3 46.9 34.4 - 439.1 9.1 39.9Foreign Exchdune 641.6 342.0 135.6 346.6 164U5 151.9 1782.2 9.1 162.0

September 17t 96U 10:36

SRI LANKA

POWER IX: DISTRIBUTION EXPANSION AND REHABILITATION PROJECT ANNEX 3.3

Project Implementation Schedule

.9. 1916 197 4988 19f 19" 199n

QtARTER R I2T3A 1 2 3 4 2 2 4 1 2 4 1 2 3 4 1 2 3 4 i 2 3 4

MV & COLOMBO CIIY NETWORK

I Engoge Ersiting Consultants fof Pte oration ofBid Documents;

2 Dtoemnation of Polo & Cooductor types

Prepaitahon of Bid t4 cutments

4 Biddngt

S Evoluaton & Awold

6 W33f trssou Lws Coc wuction H _ _ _ _ _

7 Coloembo Cniy Argumentation U M _ _ _

SELECTION OF CONSMUANtS FOR STANDARDIZMTIONStUDIES & PROJECT MAWGEMENT

i Prepare temus of RTelence

2 Agree ,th par can tot Ust

3 Preparation of Proposl

4 lender & Award

STUDIES& tECHNICAL ASSSANaC

I Selection o Pole Types

2 Selto0n of Conductox Type

3 Groundin & insulkTionCoadd,toton

4 Snt Cicui & Protection Rebly Cordiaon*

|S Pparton of Sandards & Guidelines

oOptinal Secondary Dtibutlon & SerceComrectln Equipment _

RATIONAlTION OF LV NEIWORK & MV LINfCONVERSATION

1 i Dorjurnents Teder &ConttrO |Award

2 System Improvement & ASSocKIted Cocttruction U E rUREHAhtUTATION OF V SYStEM

i Engage Consutant (ulttiy) for troning & StoresOrganizatim

2 M4obrl/atlon of Consultant (Utility)

3 Prepare & Implernent Operating Guidelines

4 fvriluate Etorpment & tool Requirernents tot8 Crevit

|S Pepare Equpmnent & ltl Specificotions

6 Pur hcte Equipment & Tools

7 Iroar Cews on Site U U E ___

8 Train Supervsors at Coxunterpart Utility

9 Prepare i Djocuments for Mcatenlrs

10 Pirrchose Matenal for Pectalidation Wobll

It ISeno t.ion Wort (Start Using Materiais fron_

12 pgiado stores (Wb! Profect)

13 Instali VehiceM0l antenOnce System (UsingPUrchsd Soft Wale)

Wowl Back-30293

-51-

ANNEX 3.4

SRI LANKA


Disbursement Profile

IDA Fiscal Year Disbursements, US$ Millionand Semester In Semester Cumulative Cumulative %

1987

December 31, 1986 0.0 0.0 0.0June 30, 1981 1.0 1.0 1.9

1988

December 31, 1987 5.0 6.0 11.5June 30, 1988 7.0 13.0 25.0

1989

December 31, 1988 7.0 20.0 38.5June 30, 1989 8.0 28.0 53.8

1990

December 31, 1989 7.0 35.0 67.3June 30, 1990 6.0 41.0 78.8

1991

December 31, 1990 4.0 45.0 86.5June 30, 1991 3.0 48.0 92*3

1992

Of#Cember 31, 1991 3.0 51.0 98.1June 30, 1992 1.0 52.0 100.0

-52-

ANNEX 3.5Page 1 of 3

SRI LANKA


Analysis of System Losses

1. Energy losses in CEB's supply system are relatively high, and wereabout 16.6% of gross generation in July 1985. Technical losses, excludingstation service usage, were about 15.11 of gross generation which, for thissystem, translates into a demand loss at peak of about 221. Thus more thanone-fifth of the peak demand is caused by losses. The economic energy losslevel for a system like CEB's is about 10 to 1 of gross generation, whichis the level expected after the proposed Project is completed. In addition,the successful implementation of CEB's plans to improve its billing andmetering system would reduce non-technical losses from the present level ofabout 1.1 of gross generation to about 0.6%.

2. Table 1 shows the trend of losses on CEB's supply system from January1981 to July 1985. Losses fell to 151 of gross generation in 1983 but thenincreased to 16.61 in 1985. There appears to be no technical explanation forthis trend, and thus the variation probably is due to non-technical losses.

3. Tables 2 and 3 show estimated breakdowns of losses for the presentand following completion of the proposed Project; the energy losses are shownin Table 2 and the demand losses in Table 3.

4. The highest losses occur on the MV distribution system (33-kV andII-kV), and consequently most of the effort of the proposed Project isdirected to this level. This is unusual since in most supply systems thehighest losses are usually on the LV system, but CEB sells only about 25Z ofits energy at the LV retail level. The project would reduce losses at the NVlevel by: (a) establishing 33-kV as a distribution voltage; (b) convertingsome 11-kY feeders to 33-kV operation; (c) reducing the length of existing33-kV feeders; and (d) adding capacitors for power factor correction. Recon-ductoring some existing 33-kV feeders would have had the same effect asintroducing express feeders to break up existing feeders into shorter runs.However the latter approach was chosen since it has a considerable advantagein improving system reliability and is also easier to implement.

5. Losses at the LV level would be reduced by using more MVILV trans-formero, thus reducing the Length of the LV feeders. Also in some places twoadditional LV phases are added where there is single phase distributior.This has the effect of reducing significantly the current on any one phatseand thus the losses.

6. Pinally, the rehabilitation portion of the project would improveconnections, especially bimetallic connections which are prone to corrode andcause heating.

ANNEX 3.553 Page 2 of 3

Table 1

CEYLi. ELECTfICI TY SOAR - EN8 BALANCE

3m05s Q1tl ton StatlIon _ st n raftIan Se s an Grnss on 0 staitnb Actuei Ave ,q Ausl [l riaes Actual Avesq ACtuol vetsm Gesriation G wmttan

Janus r* 157.327 1.358 155.969 230.969F*oruaty 139.695 2.09 -t37.626 120.539

'rcn t58 .43 t.734 136.70t 108*627Apr11I 3i0.204 2.304 127.9O, I04.062bi4 y t37.597 1.779 M35.5 t4 tM92ttJune 1t44 824 1196 243.628 114.514

July 166.466 0.605 165."6 128.799August 168.398 0.605 t67.493 15.435

Wi D r 166.44 1.320 167.424 134.315

O3tcoor 172.148 1.0900 171.056 t36.81t

t4oveaor 170.804 0.946 t69.B58 238.237404eesar *77.0a7 155.970 2.0Zt 175.066 t54.575 155.2il 125.1)7 19.8 19.1

29tJanuary t72.268 t57.214 t.943 170.325 155.772 143.853 126.t90 t9.7 19.0Femoruy 156.706 554.632 2.695 t54.011 257.230 131.640 t27.1t5 29.8 19.1

Nlecn 169.097 161.187 2.092 167.005 159.662 t27.899 128.721 20.t 19.4

Aprl2 159.55d 163.633 2.074 157.484 162.128 133.870 131.205 29.8 19.1

_bv 170.680 166.390 1.970 t68.7t0 164.669 t42.275 133.569 19.7 19.0

June 172.600 168.705 0.564 t72.036 167.236 138.639 135.579 19.6 18.9July 17d.802 169.733 0.601 178.201 168.264 140.986 136.59 t9.5 18.8August 178.667 170.572 0.627 178.;40 169.102 146.242 137.496 19.3 28.7

Seaptemr 17.786 170.B50 0.746 171.040 169.405 148.325 138.663 t8.8 18.1Octoe r 279.034 171.341 2.313 176.521 169.858 124.830 139.331 18.7 28.0Novr4Or 179.td 172.039 0.927 178.253 t70.558 147.088 140.077 18.6 27.9

:e"mor 178.385 172.247 0.944 177.441 170.756 140.327 140.498 18.4 17.71983

January 179.168 172.724 1.588 177.600 17t.362 151.037 141.096 28.3 17.7Fvsbrusy 166.506 IT.524 1.552 164.744 t72.256 145.348 142.239 18.0 27.4VArn 146.049 174.940 1.823 284.272 173.69 142.699 143.472 28.0 17.4AorIl 1 65.448 175.431 1.942 163.506 i74.197 140.866 244.055 t7.9 27.3;3at 179.455 176.162 2.255 177.202 It4.i5 254.743 145.094 17.6 17.0June 1'7.792 177.428 2.042 185.750 176.047 162.733 147.102 27.2 16.4July 173.20t 176.962 2.991 171.017 t75.449 t55.543 148.315 16.2 15.5August 172.040 176.410 1.2Idl 170.859 274.850 142.946 148.040 16.1 15.3Septamer 176.398 176.794 1.207 175.191 175.196 152.551 148.393 16.1 15.3October 183.465 t77.240 0.935 182.930 275.730 255.976 149.322 15.6 15.0'oedor 171.266 176.620 1.582 169.684 175.016 145.763 149.211 15.5 14.704cber 173.337 176.200 2.36' 170.973 174.477 142.180 149.36 t5.2 24.4

284SJnuary 171.254 175.539 1.376 169.88 273.534 145.667 148.915 15.2 14.3Feprwry 160.485 175.754 0.664 168.222 174.124 44.644 148.859 25.3 54.5VArn 192.192 176.262 '.299 190.992 124.576 155.055 149.889 25.0 24.2Aprl I 177.391 177.257 0.543 176.8W 175.783 253.059 150.934 15.9 24.2wav t90.'02 275.244 0.513 189.5S9 176.920 153.983 150.840 15.3 "4-7Juno 192.075 178.418 1.J99 2t9.972 277.242 156.379 t90.322 15.7 15.2JuIY 191.629 179.953 0.752 190.671t 78.825 155.679 250.322 26.5 25.9

August 200.751 282.545 0.43 199.908 281.247 162.351 151.936 26.7 16.2Spt.moen 289.925 183.4735 0.97 189.028 182.400 166.209 153.075 16.6 16.2

cttocer 198.356 184.680 0.857 197.499 183.614 238.963 153.323 17.0 12.5r4o4ei"r 2905.472 186.597 0.d64 194.1o4 265.591 t69.265 215.235 26.8 26.4Oecdicer 193.002 td8.336 M.6d9 192.1123 '7.455 255.315 156.378 17.0 16.6

Jifon"Y 202.906 190.974 0.831 202.0'5 190.136 165.575 158.020 17.3 26.9eoDnIore 285.445 192.204 0.d03 182.642 t9'.354 256.860 159.288 17.1 16.8

wal't 204.3415 193.553 1.267 207.1 8 192.706 170.329 160.56t t7.0 16.7Abril 414.17V f25.119 1.128 195.051 294.223 170.491 162.015 27.0 26.6

My 204.03? 196.280 2.329 201.708 195.233 172.737 163.578 27.7 16.2Juno 29.513 196.900 0.946 191.567 t95.866 t67.786 164.529 24.4 16.0Jul# 21t.912 198.5d2 1.417 210.395 197.492 168.253 165.577 16.6 16.2

-54-


Table 2

8AEAKOOWN OCF EXISTING AND PROJECTED ENERGY LOSSES

Losses (S of Gross Generation)System Component Present End of Project

Station auxiliaries &/ 0.4 0.4Step-up transformers 2.0 2.0Transmission lines 3.9 3.9Grid substation transformers 1.8 1.9MV distribution lines 4.8 1.61V/LV transformers 1.3 0.7LV lines 1.3 0.3Mon-technical 1.1 0.6

Total 16.6 11.4

a/ Strictly speaking, station auxiliary usage is not "losses". 0.4% Isa good value for a predominantly hydro system.

Table 3

BREAKDOWN OF EXISTING AND PROJECTED DEMAND LOSSES

Losses (% of Peak Generation) a/System Component Present End of Project

Station auxilIaries 1.0 0.9Step-up transformers 2.0 2.0Transmission lines 5.8 5.8Grid substation transformers 1.8 1.8MV distribution lines 7.1 2.5MV/LV transformers 1.2 0.7LV Lines 3.3 0.7

Total 22.2 14.4

at Demand losses are at peak load for the system.

ANNEX 3.6-55- Page 1 of 3

SRI LANKA


Equipment Technical Parameters

Th. major equipment for the proposed Project have been planned basedon the specifications outlined below. These may undergo changes after thesehave been reviewed by the consultants.

Main 33 - kV Lines

The main 33 - kV lines, which would be constructed cross countrywould have the following characteristics:

Conductor: 0.175 in.sq. ACSR-LYNXCurrent rating: 400 ABasic insulation level: 200 kVPBasic span: 273.0 yds (250 m)Ground clearances: 16 ft.Maximum fault current: 25 kA

The maximum sag would be designed for a wind force of 12 lbs. per square footand a maximum temperature of 60 degrees C.

Lines in Urban Areas

The lines through the urban areas would be on steel poles with abasic span of 100 m. The support insulators would be either pin or line posttype. The following British standards or equivalent IEC standards would beused:

ACSR Conductor: BS 215Hard Drawn Copper Conductor: BS 125Steel Wire: BS 183Insulators: BS 137

The distribution lines would be on either steel, concrete or woodpoles with a basic span of 54.5 yds. A comprehensive study would be carriedout for the selection of suitable supports. The conductor would be -.075in.sq. ACSR (Racoon) or equivalent all aluminium and supported on lO kN pininsulators.

-56- ANNEX 3.6Page 2 of 3

Distribution Protection

The 33 - kV lines would be protected with overcurrent relays withearth fault protection at grid sub-stations. The protection scheme wouldalso include auto reclosers, sectionalizers and sectionalizing fuses.

The 33 - kV auto reclosers would have the followirg characteristics:

Type: VacuumNominal Rating: 400 AFault Rating: 8 and 16 kA-BIL: 170 kVP

The reclosers in remote-areas may be of the lower fault rating of 8 kA. Thereclosers would be protected against surges by the use of surge arresterstand would be provided with 3 sets of link cutouts to facilitate maintenance.

Distribution transformers would be protected with expulsion fuses andsurge arresters. The fuse characteristics would be toordinated with those ofthe auto reclosers.

Power Factor Correction Capacitors

Unswitched capacitors would be provided along the distribution lines.The capacitors would conform to IEC 70 and be of Non-PCB all film dielectrictype. They would be protected with expulsion fuses and surge arrestors.

Distribution Sub-station

The proposed distribution sub-stations would be in the range of 50 to160 kVA to minimize secondary losses. They would be pole mounted andprotected with expulsion fuses and surge arrestors. The transformersgenerally would conform to IEC-76. The insulation levels of transformerswould be as follows:

Rating 11 - kV 33 kVBIL 75 kVP 170 kVPPower Frequency 28 - kV rms 10 kV rms

The windings would be of copper and the transformers would be type testedfor short circuit withstand capability as per BS 171/1978-part V.

The lightning arrestors would be of the distribution class and eitherof valve or Zinc-oxide type. The former would conform to IEC 99. Thecharacteristics of the arrestors would be chosen in accordance with systemrequirements and so as to achieve proper insulation coordination.

The expulsion fuses would conform to IEC 282-Part 2 and be providedwith suitable hooks for disconnection using load busters.

AMEX 3.6Page 3 of 3

-57-

33/11 - kV Primary Sub-station

The 33 - kV switchyard would be of the outdoor type. The 33 - kVcircuit breakers would conform in general to IEC 56 and be either bulk oil,vacuum or SF 6 type. The fault rating shall be 25 - kA.

The power transformer would conform to TEC 76. It would be providedwith an on-load tap changer on the LV winding. The vector group would be DY1. The full load temperature rise of transformers would be limited to 50degrees C.

The 11 - kV switch gear would be metal clad indoor type. The circuitbreakers would be either bulk oil, vacuum or SF 6 type. The fault ratingwould be 20 - kA. The neutral of the 11 - kV winding would be earthed.

Cables

The 33 - kV cable would be PILCDSTA type. It would conform to BSS6480 Part 1. It would be of the belted type with PVC extruded bedding. Itwould be paper insulated, non-draining oil impregnated type. The faultrating would be 25 - kA. Suitable rated XLPE cable would also be considered.

The 11 - kV cable would either be PILCDSTA or XLPR type conforming toBSS 6480 and BSS 5468, respectively. The fault rating would be 20 - kA. Theconductor would be of stranded cooper complying with BSS 6360: 1969.

The LV cables would be 4 Core, 600/1000 V oil impregnated paperinsulated conforming to BSS 6480 Part I of 1969. The conductor would be ofstranded copper conforming to BSS 6360-1969. The fault rating would be 40 -

kA. Suitably rated XLPE cable would also be considered,

SRI LANKA

POWER IX; DISTRIBUTION EXPANSION AND REHABILITATION PROJECT

Actual and Forecast Income Statements (Year Ending December 31st)

(SL Rs Million)

......... ACTUAL......... (unaud.) (Budget) .................. .. FORECAST ..............

1980 1981 1982 1963 1984 1985 1986 1987 1988 1989 1990, 1991 1992 1993 1994 1995

KWh GENERATED (N$ILLIO4S) 166 187 2066 2114 2261 2464 2815 3071 3345 3648 3975 4334 4728 5153 5617 6118

KWh SOLO (KILLIONS) 1392 1503 1679 1792 1877 2061 2308 2549 2810 306 3379 368 4066 4432 4943 S384

KWh SOLD/KJh GENERATED(%) 83 80 81 as 83 84 82 83 84 84 e5 85 66 86 a8 a8

AVE. TARIFF/KWh SOLD(CEIITS) 37.36 58.62 77.55 84.49 - 78.00 136.20 149.00 165.39 170.35 182.28 202.33 220.54 227.1 233.97 240.99 248.22

OPERATING REVENUE

SALES OF ELECTRICItT 520 881 1302 1514 1464 2807 3439 4216 4787 5586 .683 8124. 9236 103U8 11912 1336

FUEL SURCHARaE 367 758 1140 2507 566 114 41 106 309 659 1005 840 1555 1325 2181 2255

OTHER OPERATING REVENUES.. ... ... ... 224 146 153 161 169 177 186 196 205 216 226 238

OTHER REVENUE . . .. .. . . 169 244 231 279 381 423 343 376 463 558 542

TOTAL OPERATING REVENUES 887 163,9 .. 244,2 .. 4,021 2254 3236 3878 4714 5544 6803 SW5 9504 11373 12372 1487 1639

OPERATING EXPENSES

FUEL COST 254 560 971 2311 489 III 40 103 300 640 976 816 1510 1286 2117 2189

OPERATION & MAINTENANCE 85 132 167 207 288 341 479 598 7110 843 1009 1193 1370 1549 1750 1997

TURNOVER TAX 12 31 51 46 20 88 104 130 153 l87 235 269 324 3S1 423 469

ADMINISTRATION & OTHER 52 101 110 255 187 172 189 208 229 252, 277 305 335 369 406 446

DEPRECIATION 154 256 329 371 460 641 958 1197 1419 1445 2018 2386 2740 3098 3500 399 ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - I

TOTAL OPERATING EXPENSES 557 1081 1628 319 1444 1353 1770 2236 2811 3607 4516 4969 6279 66S3 8195 99

MET OPERATING INCOME 330 558 814 831 810 1883 2108 2478 2733 3196 3935 4534 5093 5719 668 730

INCOMIETAX 0 0 282 438 46 169 31 155 0 0 0 0 0 0 0 0

NET INCCII AVAILABLE 30 558 532 393 764 1714 2077 232 2733 3196 3935 4534 5093 5 719 6682 7303

INTEREST 27 63 95 108 321 409 60? 686 980 1369 1959 2619 3073 3122 3580 4367

INTEREST CHARGED OPERATIONS 27 63 95 10 321 409 607 686 980 1369 1959 2619 3073 3122 358 4367

INCOME 303 495 436 28S 443 1305 1470 1637 1753 1827 1976 1915 2020 2597 3102 293

LESS:RESEARCH S EVELOPMENT 0 0 0 0 7 40 164 69 34 0 a 0 0 0 0 0

NETi PROFIT 33 45 46 25 36 1265 130 156 1719 1827 1976 1915 2020 2597 3102 296

RATE OF RETURN ON AVERAGE *ETFIXED ASSETS IN OPERtATION 9.40 11.38 8.66 5.64 7.38 10.6 9.09 8.07 8.11 8.06 8.32 8.13 8.02 8.08 8.46 8.15

SRI LANKA


Actual and Forecast Sources and ARpplcations of Funds Statements(Year Ending December 31st).

(S Rs Million)....... ACTUAL ......... (Urio.) (Budget).....................FOlECAST................

198 1981 1982 196 1964 1983 1986 1967 1968 1989 1990 1991 1992 1993 1994 1995INTERNL SOURCES

MET INCONE AVAILAOLE 330 358 814 831 810 1883 2108 2478 2733 3196 3935 4534 5093 5719 6682 730OEPRECIATION 154 256 329 371 460 641 958 1197 .109 1683 2018 2386 2740 3098 3500 3995LESS:RESEARC & DEVELO "EI 0 0 0 0 7 40 164 69 34 0 0 0 0 0 0 0TOTAL INTERNAL FUNDS GENERTED 485 814 1142 1202 1263 2484 2902 3606 4118 4881 5953 6921 784 8817 10182 SIM9EQUITY CONTRIWUTIOwS 117 55 238 95 1434 4537 4957 245 166 167 179 190 1I" 208 217 22OThE CONTRIBUTIONS 314 121 285 647 121 255 196 259 339 436 566 600 627 655 685 7168MORRCINGS

RUPEE LOANS 511 238 65 0 2000fOREIGN LOANS 124 54 96 1371 948 433 1227 2026 3136 3555 677 5509 3722 4105 7324 10195PROPOSED IDA CREDIT 97 431 542 331 24PROPOSED ODA LOAN 29 75 150 110 6

TOTAL BORRGINGS 635 292 161 1371 2948 433 1227 2152 3642 4247 7211 5539 3722 4103 7324 ¶0195TCOTAL SOUCES OF fUNDS 1550 1282 1826 3315 5765 7709 928 6262 8265 9731 13910 13250 12382 13786 18408 22436VI

APPLICATIONS OF FUNDS

CAPITAL iNV!STNENTS

THft PROJECT 177 836 1275 961 102OTHERINVEiSTRENTS 0 0 0 0 0 70 10 10 10 10 10 10 10 10 10 10CONSTOUCTION PROGRA 688 941 982 1660 5133 4659 783 4275 5325 5936 10940 925 6837 7584 12645 17404

TOTAL CONSTRUCTION PROGRtAM 688 91 982 ¶66 5133 4729 7847 4461 6170 7221 11911 9370 6847 7594 12655 '17414DEST SERVICE

INTEREST 27 63 95 1c8 321 409 607 686 980 1369 1959 W69 3073 3122 3580 436?'AMORTIZATION 39 97 86 120 155 344 359 356 362 366 374 524 1077 1703 1677 1984TOTAiL DEST SERVICE 66 160 ¶81 228 476 753 966 1042 1342 1735 2333 3143 4150 4825 5257 6351INCVIIXTAX 0 0 282 438 46 169 31 155 0 0 0 0 0 0 0 0INSUANCE ESCROIW ACCOUN 142 43 51 61 A4 as 97 109 124 142CHANGES IN RESERVE 917VARIATION IN WORKING CAPITAL

CASR INCREASE 106 -159 98 -163 781 1667 -132 481 1016 421 -799 326 873 949 -160 -19,45OtHER THfAN CASH INCREASE 690 340 283 1152 -671 -525 428 79 -314 293 391 325 415 308 531 474MET INCREASE 79 11 8 989 110 1141 297 560 702 714 -408 651 1288 1257 372 -1471TOTAL APPLICATIONS OF rulS ¶550 1282 1526 3315 5765 770 9282 6262 8265 9731 13910 13250 12382 13786 148 22436 4,DEBT SERVICE COVERAGE 7.40 5.09 6.30 5.26 2.65 3.30 3.00 3.46 3.07 2.81 2.55 2.20 1.89 1.83 1.94 1.78 aSELF FIRANCING RATIO( ) 0 68 72 24 21 14 30 36 40 33 48' 39 37 36 41 46

SRI LANKA

POWTER TX: DISTRIBUTION EXPANSION AND REHABILTTATION PROJECT

Actual and Forecast Balance Sheets (As of December 31st)(SL Rs Million)

...... A...OCTAL ......... (Unw4. ) (sufget).....................FORECAST .............1960 1981 1982 1983 1984 1985 1986 1987 1988 1969 1990 ¶99 1992 1993 1994 1995

FIlED ASSETS

FIM7 ASSETS IN WPERATrOR 6661 8641 11006 1297 1972 27276 36559 43228 51391 60950 M361 85485 9720 10933 123966 142334LESSM0.P.OERECA1IWS 182 2557 3310 394 5009 6306 789 9880 2189 14849 17996 .21192 24886 291404 339`13 39434

lET FTIEE ASSETS IN OPERATIO 65N08 79 9032 14713 20970 28665 3338 322 411 551 49 21 820 903 ¶20CW42rUCTIG to PRMi55 376 812 103 1790 2462 16(30 3082 4520, 6408 8171 12044 1282 11808 11635 14568 19183

TOTAL filmE ASSETS 5035 689 872 10321 1775 22M7 31747 3786 45610 54272 67659 7M35 84125 91865 104621 12208

1114CS11ENTS 2 a 8 8 13 83 913 103 11 123 133 .143 153 163 173 18t*S:VCW ESCMI ACC(MT 142 165 236 297 371 456 553 063 la? 929

4:~EWT ASSETS

CAS~~~~~~ 221~~~zz 62 159 .3 M7 2444 2312 2793 3809 4231 3432 3758 4631 S50S42 34753T~~~~IES ~~~~284 717 776 1046 820 922 1828 2161 128 1524 1840 2137 2430 2733 3099 3558

£-3CWS efE7IvAB2zE 326 507 1317 1545 1604 1169 1305 1080 1274 1561 1960 2241 2698 292 3523 39050T$~ "R! -MEVA31.fS 572 578 576 1319 346 452 497 547 602 662 72 801 881. 969 1066 1172

T0C CWSE1T AsfsIIS 1403 186 22 397 3549 4987 5943 652 6970 777 76 8937 1040 1205 130 12110

TCO0% ASSETS 6640 879 I16 ¶4734 27? 274 72 4473 5292 6269 76123 8671 9S471 1089 11868 .5305

W -AID i.:ASUTMES

677 73 969 10o5 2498 703 11992 1223 12403 12570 127,49 1293 13138 13346 1356 13791C' t _,T ~tsf 348 G68 753 14013 1521 1776 1972 2231 2570 300 3572 4172 4600 5455 6140 6856Frur-LA11,13 G~,TrLS 2721 3901 5067 5871 732 8931 1 1029 1389 16897 20033 23537 26040 2893 32187 35797 39O5

CEWIF EAVN:=$ low ISO3 1999 2814 368 403 5339 690? 8626 10454 12430 14345 16365 18962 22065 25000

1r4t Eaurn-40 66" 8788 115 1505 21775 30332 35271 40496 46062 5228 57496 63236 6995 7756 85497

L3r. T:Em ize¶26 ¶453 1539 2259 4820 4909 5777 7573 10353 14734 21571 26586 2923.1 31633 3728 45491

~~ L~~~1TZES 373~~I? 653 1237' 1327 8a9 15 1815si 1894 1580 1873 2264 2590 3004 3313 3844 431

UP~t;I'f AID 43311T!ES 644 86 1156 1473 2073 278 37924 44738 52929 62669 713 861 941 149 169 150

-- 51 Jr is~~1 1 15 17 24 18 16 18 2 4 29 32 32 31 32 35MI" ol C-l71-B *TITY78 82 85 83 76 82 84 82 7 6 7 8 68 69 68 65

-61- ANNEX 4.4

SRI LANKA


Assumptions for Financial Projections

..ocome Statement

Load Forecast: CEB's Load Forecast as agreed with the Bank.Sales Revenue: Tariff increases assumed to satisfy the covenanted 8% Rate of Return

and to meet entire Local costs of the Investment Program.Fuel Surcharge: The Fuel Cost and Turnover Tax on fuel would be recovered by levy of the Surcharge.Other Revenue: Overhead Recoveries Price variance etc. Assumed to increase at 5% p.a.Income From Excess Cash: 10% of Previous Year's Cash BalanceOperation & Maintenance: 1.5 X of Average Gross Fixed Assets in Use.Turnover Tax: 3 % of Total Operating RevenueAdninfstration & Other: Increases annually by 10 XDepreciation: 3 % of Average Gross Fixed assets in use.

Balance Sheet

Fixed Assets: At Current Cost.Cash: Minimum 2 Months$ Cash Operating Expenses.Inventories: Forecast as % of Gross Fixed Assets as follows:

1986 5.01987 5.01988 2.51989 2.5

1990-95 2.5Accounts Receivables: Forecast in Months of Sales as follows:

1986 4.51987 3.01988 3.01989 3.0

1990-95 3.0Other Receivables: Assumed to increase by 10% each year.current Liabilities: Forecast as 50% of Current Assets Other Than Cash

Flow of Funds Statements

Other Contributions: Increases assumed to finance Service & Bulk Supplies.Capital Investment: CEB's 10-year Investment Program in Current PricesInflation Rate 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

Local 10 10 9 8 7.6 4.5 4.5 4.5 4.5 4.5Foreign 7.0 7.0 7.5 7.6 7.8 4.2 4.6 4.6 4.45 4.5Escalation FactorsLocal 1.050 1.155 1.264 1.362 1.479 1.567 1.638 1.711 1.788 1.869Foreign 1.035 1.107 1.188 1.268 1.376 1.458 1.524 1.593 1.664 1.739

Other Investments: At Rs. 10 million a year beginning 1986.Debt Service Coverage: Defined as number of times debt service covered by gross internal cash gene-

ration, to be not less than 1.5 beginning 1986.Self-financing Ratio: Ratio of internally generated cash. net of Debt Service and Change in Working

Capital,to Investments averaged over the preceeding,current and succeeding years.Insurance Escrow Account 0.1% of G.F.A.

-62- ANNEX 4.5

SRTI LANKA


CEB's Tariffs - Effective from March 1, 1985

DOMESTIC - First 30 units (0 Rs. 0.50 cts. per unit31 - 150 units @ Rs. 0.90 cts. per unit151 - 500 units R@ s. 1.80 Ots. per unitAbove 500 units @ Rs 2.25 cts. pet unit

Mdinimum Charge for a month is Rs. 51-.

Fuel Adjustment Charge when in operation is applicable on units in excess of 150 per month.

For a period of 12 months. from 1985-0301l the Fuel Adjustment Charge is zero percftt.

RELICIOUS & CIHARITABI.E INSTITUTIONS- -IS0 cents per unit.

No Fuel Adjustment Charge.

Minimum Charge for a month is Rs. 51.

OTHER CATEGORIES

General Indwtrial HotelsPurpose Industrial Hotels (Time of Day) (Time of Day)

Supply at 400'230V.Contrmt demand les thasn 50 kVA

Unit Charge (Rs-Unim 1.70 1.55 1.70 _

Fixed Charge luplo 10 kVA.I. e 1-(Rs.) 20.017 20.00 20.00 _

or or or

Fixed Charge (abasc 10 kVA.)(Rs.) 100.00 100.00 100.00 _

Supply ast 400 230VContract Demandl0 kVA and above

Demand Charpe (Rs kVA.; 125.00 10000 150.00 500C 50.004- 4- 4-

Unit Charge (Rs lnit) 1 60 i145 1.60 1.35 (Off Peak) 1.35 (Off Peak;4- I-

1.90 (Peak 1.90 (Peak6pm.to9pm.) 6pm to9pm.)

1~~~~~ t ~~~~~+ 4-Fixed Charge tRs.) 200.00 200.00 200.00 200.00 200.00

IlT Supply at Ilk'33 WV. and 132 kV.

Vemand Charge (Rs kVA I 115.00 90.0) 140.00 45.00 45.00+ + 4- + f

Unit Charge IRs. tnmtl ISO I 25 1.50 1.20 (Off 1.20 (OffPeak) i Peak) +

1.75 (Peak 1.75 (Peak)6 pm. to 9 pm.I 6 pm to 9 pm.)

+ 4- +-4 1-Flied Charge (Rs.) 200.00 200.00 200.00 200.00 200.00

'4OTE I For the 12 months period frorr 19K5-03-01. tht ruet Adjustment Charge wil be zeropcrcent

The Fuel Adjustment Charge will be expresxed as a percentage and is applicable on the UnitCharges only.

The Fuel Adlustment Charge when in operation shall apply to all General PurposeIndustrial and Hotel consumers.

-63- ANNEX 4.6

SRT LANKA

POWER IX: DISTRIBUTTON EXPANSION AND REHABILITATION PROJECT

Investment Program - 1986 to 1995(SL Rs Million)

1t4t 198" 1098 1989 1t90 1991 1992 193 1994 1495PROECT .... .... .... .... .... **.ts o .gnT...OMfsn'oa Fri'n,t

FOtr1n Totol Porioq Total Forelgn Total Ftorlgn Totat foreoin Totol Foreign Total foreign totol torolgn Totol toreIgn Total toreign TotalOr401rg Cwrrtlon..................

CaflonlmUt2 0 222K otle Wnit 3 239 275 3? 44Kla*nitsaea Redab. 40 49 2? 33 10 12Ravdaninlalo .. 4500

It. h 101 19f 48 60 13 IT

SX Total 7 5 325 *--7 3 Feasibility Studies...................

Coal Project 6? 855TZ Stud' 16 S I? 34 12 25Lpp.r Kotmlo 25 47 13 25Salhul0y. 3 9 1 9

Sub Total -7 - 1 U -75 -- --

Pliged - GC ratin....................

Rant .S 1W 48 76 470 7?5 107S t564 389 540Sroadln' 30 -W .25 t1 809 1312 429 695Siwl tws t-12015 223 426 105 1868 1302 1744 84 274 2282 2712 632 737Coat Uait I t 150 W63 93 33? 503 2176 3254 58 5172 1526 2283Coat wnit 11 ISO NW .4 69 249 36 1559 2276 2444 3569 1078 157sCoal unit III 300 W 96 14 501 I1 313? 4582 491? 7183

er Kotmat. 240 NW 313 508 763 123? 284r 461?CoUlUnit IV 3OC W - t..109 159Kukut. 180 W244 401 595 978

4h Ttoali3l il 11 w75 11 12

Oriong Traramission....................

Trlrrlon IV 312 604Tramlr910n VI 374 621

Sub Total o t22-

Pild - Transmission......................

transmission D0wtopmnt .146 205 273 388 296 418 79 99Cost Project Trw. I ... 265 403 1108 1682 606 922 360 54? -Ot¢r Traanssion 62 8 I 1S 25 0 0 135 189 181 262 221 32? 82121 7 100Csi Project Trwm. i U......626 951 1t44 2649 1367 2076

Sah Total - 46 - m * 7t K 6 I1 7113 7 1111 W 8 7 7? tUo 75 14U 117

Ongoir Olstribution....................

Rural Etectriffication 105 166 80 185 89 155 96 16? 103 180 109 190 114 199 120 208 125 21? 131 22Pltrd Distribution

33 IVt tror_m siean 0 0 184 277 19? 299 212 322 229 347 0 0 0 0 0 0 276 420 289 439SUbtation s pu Lnes 0 373 0 478 0 604 0 72? 0 876 0 556 0 678 0 8t8 0 948 0 1108Dist. Expension I Rehab. 0 0 126 177 606 836 789 1275 483 961 29 102 -

Sub Total 05 7w -tOOt 232 Um 171T1 575 0 8t8 75 13 YOther Inwet_nt................

Otffice Eqip. & uildinp a 69 0 60 0 51 0 55 ... 7? ... el 85 ... 89 ... 93 97Training 38 53 49 E5 37 56 12 24Motor Vehicles 0 7o 0 77 0 6 0 91 8 104 1 ... 114 119 124Other 0 140 0 148 0 174 0 203 234 248 ... 259 2.. 270 283 295

Suh Total U 3 - M7 -W ¶0 - W 55 7 4f f 7

Total Investmnt t516 81-W 7281 7 151191 - 4 7 TM5 TM 1*--. *----=55 -- 555 asEs aoe *--s, *---- *---s as. s-t -- st a-t tess -55 nat............ sEt... ass.. *t.-- *- ts

-64-SRI LANKA ANNEX 4.7

POWER IX: DISTRIBUTION EXPANSTON AND REHABILITATION PROJECT

Fixed Asset Formation(SL Rs Million)

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

investment (1985 Rs) (Unaud) .*--- ..----.-.-- Projections ................................

Generation 5742 2760 3431 3500 7347 6967 4699 4808 7795 12937Transmission 1225 205 471 846 1780 1111 809 1278 2770 2176Distribution 539 1116 1893 2491 2365 848 877 1026 1586 1774Other 331 370 366 373 409 433 453 473 495 517

Total 7837 4451 6160 7211 11901 9360 6837 7584 12645 17404a==== uu=tu ===== =-==- :-=1::- =a== ===== ==Z=== ===S2 t==an

Escalation Factors-Local 1.050 1.155 1.264 1.372 1.479 1.567 1.638 1.711 1.788 1.869Escalation Factors-Foreign 1.035 1.107 1.188 1.278 1.376 1.458 1.524 1.593 1.664 1.739

2gn UUUa unuu= UU2UU uuuu uum= uuu *

Gross Fixed AssetsOpening Balance 19722 27276 33831 36844 41117 46564 54593 63155 71026 78783 88496Additions 7554 6555 3014 4272 5448 8029 8561 7872 7757 9712 12789

Balance Before Revaluation 27276 33831 36844 41117 46564 54593 63155 71026 78783 88496 101284

Acc. DepreciationOpening Balance 5009 6306 7264 8460 9880 11565 13583 15970 18710 21808 25307Annual Depreciation 1297 958 1197 1419 1685 2018 2386 2740 3098 3500 3995

Balance Before Revaluation 6306 7264 8460 9880 11565 13583 15970 18710 21808 25307 29302

Net Fixed Assets 20970 26567 28384 31237 35000 41010 47185 52317 56975 63188 71982

Work In ProgressOpening 8alance 2462 1800 3082 4520 6408 8171 12044 12842 11808 11635 14568Additions -662 1282 1438 1888 1763 3872 798 *1034 -172 2933 4615Closing Balance 1800 3082 4520 6408 8171 12044 12842 11808 11635 14568 19183

Revaluation of Assets

Fixed Assets 27276 33831 36844 41117 46564 54593 63155 71026 78783 88496 101284

Revaluation Rate 10.0 10.0 9.0 8.0 7.6 4.5 4.5 4.5 4.5 4.5Assets to be Revalued 27276 27276 36559 43228 51391 60950 73611 85485 97203 109334 123966Asset Base - Revalued 27276 30004 40214 47118 55502 65582 76923 89331 101577 114254 129545Addition to Asset Base 6555 3014 4272 5448 8029 8561 7872 7757 9712 12789Total Fixed Assets 27276 36559 43228 51391 60950 73611 85485 97203 109334 123966 142334

..... ..... . ..... ..... .. ..... ..... . ...... ..... .. ..... .... .. ........... .. ........... ..

Total Revalued Assets 36559 43228 51391 60950 73611 85485 97203 109334 123966 142334

Revaluation of Acc. DepreciationRevaluation Rate 10.0 10.0 9.0 8.0 7.6 4.5 4.5 4.5 4.5 4.5Acc. Depreciation 6306 6306 7894 9880 12189 14849 17996 21192 24886 29104 33913Acc. Depreciation - Revalued 6306 6937 868 10770 13164 15978 18806 22146 26006 30414 35439Annual Depreciation 958 1197 1419 1685 2018 2386 2740 3098 3500 3995Acc. Depreciation T Total 6306 7894 9880 12189 14849 17996 21192 24886 29104 33913 39434

NET F.A IN OPERATION 20970 28664 33348 39202 46101 55615 64292 72317 80230 90053 102900=_==== =2:=== ====55 ==_=== ====== ====== ====== u==UUU ====== u==oun uca=ee

-65- ANNEX 5.1Page 1 of 5

SRI LANKA


Economic Internal Rate of Return

As described in Chapter 5, the proposed Project forms an integralpart of CEB's least cost expansion plan and, therefore, cost-benefit analysisneeds to be carried out on the whole plan rather than on the project inisolation. CEB's investment program for the period 1986-2000 has, therefore,been analyzed. Incremental capital costs, operation and maintenance costs,and benefit streams (all in terms of early 1986 prices), are shown inTable 1. Assumptions underlying these figures are detailed below.

Capital Costs

Anticipated capital expenditure on generation (from the WASP-IIIgeneration planning model), transmission and distribution at financial priceswas converted to economic prices by (i) expressing the import content atc.i.f. prices; (ii) valuing unskilled labor at 0.80 of the market wage rate;and (iii) applying the estimated standard conversion factor of 0.75 to localcosts.

Operation and Maintenance

Annual operation and maintenance costs were estimated as the follow-ing percentages of cumulative capital costs: generating plant 2%, transmis-sion 2%, distribution 3%, and other 5%.

Benefits

Benefits in the base case were estimated solely in terms of revenueusing the average revenue per kWh in early 1986. Forecast incremental salesrevenue associated with the investment program is shown in Table 2. Theforecast allows for the impact of the projected reduction in system losses inaccordance with the targets given in para 2.11. The average revenue ofRs 1.51/kWh in 1986 was taken to represent the weighted average tariff ratedefined over existing tariffs. Projected fuel costs for thermal generationwere assumed to be recouped through the fuel adjustment charge in the tariff,in line with CEB's tariff policy. On this basis, and with costs measured ineconomic terms, the rate of return is about 9.0%.

The foregoing rate of return is not based on estimates of consumers'willingness to pay (WTP) for electricity. It is thus more a measure of theadequacy of tariffs than of the worth of the proposed Project. A better

-66-


measure of the rate of return can be obtained by estimating consumers' WTPtor the incremental electricity sales. A lover bound estimate of WTP wasderive.i as follows: for residential, conmmercial, street lighting, localauthority and government consumers, it was the weighted average tariff ratefor incremental consumption in the respective tariff categories. For con-iutferf in the industrial and hotel tariff categories, WTP was measured in

termp ot the incremental economic fuel costs of meeting their demands forelectricity using auto-generators which are displaced by the public supply ofVlcctritiLy. Calculated on this basis, the weighted average WTP for allconsumer groups is Ro 2.44IdWh. The economic rate of return (EIRR) on thisbaAsif fi abf}out 11.0%. It should be stressed that this is Only a partilmrrnmonre; of IIRK, since the use of the weighted average tariff rate torincreepitnt reunf&umpJtion in all tarift categories with the exception of hotelsanS.d industry mefna that WTP io generally undereAtimated Since no allowance inmade for coinrsimerfis nurplus. In additifont the measure assumes that con-

*toswrr' WTI' for flo- imprfived rel inilit'y and qua)lt y of electricity supply in

5fan,ftitvily nrinlysiiis wnfl cuirrietd owt arnimiri a IOS reduction in WTP,ni 10i7 iit( rea (npil u tfnioid, ntrd varin i nm ilroiject-ed salMen by +lQXmifl{l 11',. 'lf*s ie'n*.$r- w *mrrifiri n?eml in Tnb)ehl 3.

-67- ANNEX 5.1Page 3 of S

Table 1

Economic Internal Rate of Return /a

(SL Rs Million)

Capital OperationsYear Costs & Maintenance Benefits Balance

1986 2317.6 58.8 431.9 -1944.51987 6196.9 184.4 791.2 -5590.11988 4741.9 277.1 1189.9 -3829.11989 5954.6 388.1 1570.4 -4772.31990 6678.1 507.6 2047.6 -5138.11991 4967.4 592.2 2506.6 -3053.01"2 3853.4 660.1 3063.8 -1449.71993 3980.9 730.5 3631.6 -1079.81994 6402.2 839.7 4398.6 -2843.31995 8400.8 979.4 5073.6 -4306.61996 8534.8 1121.3 5765.2 -3890.91997 8990.6 1270.0 6514.1 -3746.51998 7318.0 1392.9 7325.0 -1385.91999 3382.1 1456.9 8211.4 3371,82000 1014.3 1485.5 9165.7 6665.92001 - 1485.5 10204.6 8119.1

2002-12 1485.5 10308.8 8823.3201 314 1485,5 9032.8 7547.32015-)6 1405.3 7756.9 b271.4201 1-1 1495.5 5452.6 3967.)21119-33 1485.5 3146b. 166h.3

hat-et d Htiltafn - 0.-1

/a Al I f QiIIt fi Ver *4pceifti(Jtl Li tf1RfiIC Itefilsfi. Pri w# I I fi hi.'# wedi f tw

Ix9Jb "wftigf, tI tt-i If Vv1#1w 131 W I'I 4 i ft I .ki. kiait,.1 Fllita ii i igWpv* t dwitti -1 Jri f4e tI f l Itt #4 1 i t s fiJflI4 i.iiI I li w#* VP (ltt vIa tati I

tf ffI,t$VP lst t ciffi'da.lulv wi Its 044 11# Iti ; tIpl If , *Wle4 tts.# f* # H t t

$If(II tJI46 itN, 1I40 w1poftfIuld scl vhiatgu'.

-68-ANNEX 5.1Page 4 of 5

Table 2

Economic Internal Rate of Return /a

tiscount Net Present CapitalRat.^ Value Cost u&M Benefits

(Rs million) (a

0% +196091 +235 +307 -575X + 42815 + 75 +226 -368Z + 13684 + 29 +124 -1910% + 3569 + 9 + 44 - 712X - 2562 - 7 - 41 + 61SZ - 7591 - 24 N/A +2720Z - 10400 - 42 N/A +6125X - 10675 - 53 N/A 495

/0 The table nhowf I1.h percentag,e chtange, compared with ba,e cage valuco,reqoairvod to mae the rate of return equal to nny ratre ohown in the tirot0umnr, Thao the r4fte of return woid4d riae to 15% if' benefito were

increswd by 27% or enaiitl eootfi were rediWeld tby 24%.

Nlh Nfl appicrableo thi jpercrertage decrearw in {f6H coato would have toexceed MOltt%, fflf' jjo tht1t the-y woiuld hiSavet toit twetitive.

-69- ANNEX 5.1Page 5 ot 5

TabLe 3

Economic Internal Rate of Return and Sensitivity Analysis

Costs Benefits EIRR (Z)

Base case Average tariff revenue la 9.0

Base case WTP /b 11.0

Variation in sales

Base case WTP with sales -lOZ 9.5

Base case WTP with sales +10% 12.5

Variation in capital costs

Capital costs +1OZ VTP 9.9

Capital costs -1OZ WTP 12.5

/a Rn 1.51/kWh.

/t ITP in fln 2.441/kWh, SCF P .15

-70-

ANNEX 6.1

SRI LANRA


Data and,Documents Available in Project File

1. Existing transmission and distribution facilities.

2. Terms of reference for consultants.

3. Project Document (Distribution Development and RehabilitationProject - CEB October 1985).

4. Project Detailed Cost Estimates - Compass 1030-1985.

5. CEB Act, No. 17 of 1969.

6. Finance Act, No. 38 of 1971.

7. Calculations for Economic Internal Rate of Return (Worksbeeta).

8.1 CEB's Financing Plan 1986-1995.

8.2 CEB's Debt Service Projections 1986-1995.

8.3 CEB'a Income Tax Liability Projections.

8.4 Methodology of Revaluation of CEB's fixed aseete, as agreed with theRnnk Cr¢up.

9. Termo of Ref rercwe for the Fixed Asset Aceountirng tudy (DthidsonLand Atiatus).

IfRD 194:

SRI LANKA

POWER IX:DISTRIBUTION EXPANSION-AND REHABILITATION PROJECT

PROPOD DeVEOPMENT IN OUTER COLOMBO REGIONS

a, ~ ~ ~ ~ ~ ~ ~ 0 to \,,>.

yX \ \ 0 to 15 IkOMIfTER$

Scaluwy \ .-

\ ~ ~~~ ~ ~~~~~~ L mr ,

'ftsaL tws..p -w.i '\,d/ sle

Ur.,A.,-,?3

1~ ~ ~ -'A p ! t,\ \

_. __r, V. .... .. 4. / --4

tt * s t tx I ~~~~~~~~~~~~, . 2 .. 6 ,

1 I I

^, . ;, rA L ¢ .*~~~~~~~~~~~~~~~~~~~~-~ ,, if . I

**i .*~ .3 .>e

,~~ {' ii ks' 19,-d

F:r p ja ' . ige + - n'*,.3

i~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~'j. 1

i ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~1

§24x ,t2 % t | i " t ' ti * t * st t.tt 4'¢ r {-* ! } *.11' **

W-

SRI LANKA

POWER IX:DISTRIBUTION EXPANSIONAND REHABILITATION PROJECT

nl* com_Sm* GCid Substations

New 0,175 in. sq. lines (double circuit)New 0.175 in. sq. lines (single circuit)Conversion of 11 kV lines to 33 kV lines

* GGanties~~~~~~~~~~~~~~~~~ ~~~~~~~~~~~~~~~~Power St:t f

* Existing@ Undet ConsuctirO Existing Grid Substations

132 kV Sysemt- existing lines

tines under coantructionPlanned lines {non-projet)

220 kV System,- Exctn lines

Lines under constuion

e National Cpitl- ntertiona Boundy

i~~~~~~~~~~~~~~~~~~~~t Iv

' l 1

t1 ,4 ,

.; t i } 8 ~-Is i j

'f1~~~~~~~~~~~~~~~~

8gce a ° m